**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe quarterly period ended June 30, 2005**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe transition period from               to              **

**Commissionfile number 1-10934**

**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of registrantas specified in its charter)

| **Delaware**                                                     | **39-1715850**                        |
|------------------------------------------------------------------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization) | (I.R.S. Employer  Identification No.) |

 

**1100 LouisianaSuite 3300Houston, TX 77002**

(Address of principalexecutive offices and zip code)

**(713) 821-2000**

(Registrant’s telephonenumber, including area code)

Indicate by check markwhether the registrant: (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes x  No o

Indicate by checkmarkwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Exchange Act). Yes x  No o

TheRegistrant had 46,802,634 Class A common units outstanding as of August 5,2005.

 

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**TABLE OF CONTENTS**
| **PART I. FINANCIAL  INFORMATION** |
|-----------------------------------------|
| Item 1.                                 | Financial  Statements |   |   |
|                                    | Consolidated  Statements of Income for the three and six month periods ended June 30,  2005 and 2004 |   | 3 |
|                                    | Consolidated  Statements of Comprehensive Income for the three and six month periods ended  June 30, 2005 and 2004 |   | 4 |
|                                    | Consolidated  Statements of Cash Flows for the six month periods ended June 30, 2005  and 2004 |   | 5 |
|                                    | Consolidated  Statements of Financial Position as of June 30, 2005 and  December 31, 2004 |   | 6 |
|                                    | Notes  to Consolidated Financial Statements |   | 7 |
| Item 2.                                 | Management’s  Discussion and Analysis of Financial Condition and Results of Operations  |   | 16 |
| Item 3.                                 | Quantitative  and Qualitative Disclosures About Market Risk |   | 30 |
| Item 4.                                 | Controls  and Procedures |   | 35 |
| **PART II.  OTHER INFORMATION**    |
| Item 1.                                 | Legal  Proceedings |   | 36 |
| Item 6.                                 | Exhibits |   | 36 |
| **Signatures**                          |   | 37 |
| **Exhibits**                            |   |   |

 

*In this report, unless the context requires otherwise,references to “we”, “us”, “our”, or the “Partnership” are intended to meanEnbridge Energy Partners, L.P. and its consolidated subsidiaries. ThisQuarterly Report on Form 10-Q contains forward-lookingstatements. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. Theyuse words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,”“intend,” “may,” “plan,” “position,” “projection,” “strategy,” “could,” “would,”or “will” or the negative of those terms or other variations of them or bycomparable terminology. In particular, statements, expressed or implied,concerning future actions, conditions or events or future operating results orthe ability to generate sales, income or cash flow or to make distributions areforward-looking statements. Forward-looking statements are notguarantees of performance. They involve risks, uncertainties and assumptions.Future actions, conditions or events and future results of operations maydiffer materially from those expressed in these forward-lookingstatements. Many of the factors that will determine these results are beyondour ability to control or predict. For additional discussion of risks,uncertainties and assumptions, see our Annual Report on Form 10-Kfor the fiscal year ended December 31, 2004.*

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**PART I—FINANCIAL INFORMATION**

**Item 1.**                        FinancialStatements

**ENBRIDGEENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OFINCOME**
| ** **                                                     | ** ** | **Three months ended June 30,**                                          | ** ** | **Six months ended June 30,**                                            | ** ** |
|----------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|
| ** **                                                     | ** ** | **       2005       ** | ** ** | **       2004       ** | ** ** | **       2005      ** | ** ** | **     2004       ** | ** ** |
| ** **                                                     | ** ** | **(unaudited; in millions, except per unit amounts)**          | ** ** |
| Operating revenue                                              |       |                                                                                         | $          | 1,332.7                                                                                      |       |   |   | $ | 969.7 |   |   |   | $ | 2,582.8 |   |   |   | $ | 1,952.2 |   |   |
| Operating  expenses                                            |       |                                                                                         |       |                                                                                         |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Cost of natural gas (Note 4)                                   |       |                                                                                         | 1,150.4    |                                                                                         |       |   | 797.5 |   |   |   | 2,222.6 |   |   |   | 1,619.3 |   |   |
| Operating and administrative                                   |       |                                                                                         | 80.4       |                                                                                         |       |   | 68.2 |   |   |   | 154.8 |   |   |   | 130.5 |   |   |
| Power                                                          |       |                                                                                         | 17.2       |                                                                                         |       |   | 17.1 |   |   |   | 34.2 |   |   |   | 34.3 |   |   |
| Depreciation and amortization                                  |       |                                                                                         | 34.1       |                                                                                         |       |   | 28.9 |   |   |   | 67.4 |   |   |   | 57.5 |   |   |
|                                                           |       |                                                                                         | 1,282.1    |                                                                                         |       |   | 911.7 |   |   |   | 2,479.0 |   |   |   | 1,841.6 |   |   |
| Operating income                                               |       |                                                                                         | 50.6       |                                                                                         |       |   | 58.0 |   |   |   | 103.8 |   |   |   | 110.6 |   |   |
| Interest expense                                               |       |                                                                                         | (25.6      | )                                                                                            |       |   | (22.0 | ) |   |   | (51.2 | ) |   |   | (43.6 | ) |   |
| Other income (expense)                                         |       |                                                                                         | 0.7        |                                                                                         |       |   | (0.1 | ) |   |   | 1.3 |   |   |   | 2.0 |   |   |
| Net income                                                     |       |                                                                                         | $          | 25.7                                                                                         |       |   |   | $ | 35.9 |   |   |   | $ | 53.9 |   |   |   | $ | 69.0 |   |   |
| Net income allocable to common and i-units                     |       |                                                                                         | $          | 19.9                                                                                         |       |   |   | $ | 30.4 |   |   |   | $ | 42.1 |   |   |   | $ | 58.0 |   |   |
| Net income per common and i-unit (basic and  diluted) (Note 3) |       |                                                                                         | $          | 0.32                                                                                         |       |   |   | $ | 0.56 |   |   |   | $ | 0.69 |   |   |   | $ | 1.06 |   |   |
| Weighted average  units outstanding                            |       |                                                                                         | 61.9       |                                                                                         |       |   | 54.9 |   |   |   | 61.3 |   |   |   | 54.8 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF COMPREHENSIVE INCOME**
| ** **                                          | ** ** | **Three months ended  June 30,**          | ** ** | **Six months ended  June 30,** | ** ** |
|-----------------------------------------------------|------------|----------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                          | ** ** | **    2005    ** | ** ** | **   2004   **  | ** ** | **    2005    ** | ** ** | **    2004     ** | ** ** |
| ** **                                          | ** ** | **(unaudited; in millions)**                   | ** ** |
| Net income                                          |       |                                                     | $          | 25.7                                          |       |   |   | $ | 35.9 |   |   |   | $ | 53.9 |   |   |   | $ | 69.0 |   |   |
| Unrealized loss on derivative financial instruments |       |                                                     | (11.5      | )                                             |       |   | (5.9 | ) |   |   | (85.7 | ) |   |   | (24.9 | ) |   |
| Comprehensive  (loss) income                        |       |                                                     | $          | 14.2                                          |       |   |   | $ | 30.0 |   |   |   | $ | (31.8 | ) |   |   | $ | 44.1 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF CASH FLOWS**
| ** **                                                                         | ** ** | **Six months ended June 30,**                                | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **      2005      ** | ** ** | **     2004     ** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**                                           | ** ** |
| Cash provided by  operating activities                                             |       |                                                                             |       |   |   |   |   |
| Net income                                                                         |       | $                                                                                | 53.9       |   |   | $ | 69.0 |   |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                                                             |       |   |   |   |   |
| Depreciation and amortization                                                      |       | 67.4                                                                             |       |   | 57.5 |   |   |
| Derivative fair value loss (Note 4)                                                |       | 16.8                                                                             |       |   | 1.7 |   |   |
| Environmental liabilities                                                          |       | —                                                                           |       |   | (2.0 | ) |   |
| Other                                                                              |       | (0.3                                                                             | )          |   | — |   |   |
| Changes in  operating assets and liabilities, net of cash acquired:                |       |                                                                             |       |   |   |   |   |
| Receivables, trade and other                                                       |       | (5.8                                                                             | )          |   | 4.0 |   |   |
| Due from General Partner and affiliates                                            |       | (13.8                                                                            | )          |   | 6.9 |   |   |
| Accrued receivables                                                                |       | (2.2                                                                             | )          |   | (90.9 | ) |   |
| Inventory                                                                          |       | (10.2                                                                            | )          |   | (16.7 | ) |   |
| Current and long-term other assets                                                 |       | (2.8                                                                             | )          |   | 11.0 |   |   |
| Due to General Partner and affiliates                                              |       | 20.7                                                                             |       |   | 2.8 |   |   |
| Accounts payable and other                                                         |       | (17.3                                                                            | )          |   | 9.3 |   |   |
| Accrued purchases                                                                  |       | 16.9                                                                             |       |   | 92.2 |   |   |
| Interest payable                                                                   |       | 4.1                                                                              |       |   | 8.9 |   |   |
| Property and other taxes payable                                                   |       | (3.7                                                                             | )          |   | 0.4 |   |   |
| Net cash provided by operating activities                                          |       | 123.7                                                                            |       |   | 154.1 |   |   |
| Cash used in  investing activities                                                 |       |                                                                             |       |   |   |   |   |
| Additions to property, plant and equipment                                         |       | (174.7                                                                           | )          |   | (70.8 | ) |   |
| Changes in construction payables                                                   |       | 2.2                                                                              |       |   | 1.0 |   |   |
| Asset acquisitions, net of cash acquired (Note 2)                                  |       | (185.9                                                                           | )          |   | (130.0 | ) |   |
| Other                                                                              |       | 0.8                                                                              |       |   | 0.1 |   |   |
| Net cash used in investing activities                                              |       | (357.6                                                                           | )          |   | (199.7 | ) |   |
| Cash provided by  financing activities                                             |       |                                                                             |       |   |   |   |   |
| Proceeds from unit issuances, net (Note 7)                                         |       | 127.5                                                                            |       |   | 22.0 |   |   |
| Distributions to partners (Note 7)                                                 |       | (104.0                                                                           | )          |   | (93.6 | ) |   |
| Borrowings under debt agreements                                                   |       | 1,837.0                                                                          |       |   | 855.8 |   |   |
| Repayments of debt                                                                 |       | (1,622.0                                                                         | )          |   | (732.5 | ) |   |
| Other                                                                              |       | (0.5                                                                             | )          |   | — |   |   |
| Net cash provided by financing activities                                          |       | 238.0                                                                            |       |   | 51.7 |   |   |
| Net increase in cash and cash equivalents                                          |       | 4.1                                                                              |       |   | 6.1 |   |   |
| Cash and cash equivalents at beginning of year                                     |       | 78.3                                                                             |       |   | 64.4 |   |   |
| Cash and cash  equivalents at end of period                                        |       | $                                                                                | 82.4       |   |   | $ | 70.5 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF FINANCIAL POSITION**
| ** **                                                                                                  | ** ** | **June 30,  2005**                | ** ** | **December 31,  2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                  | ** ** | **(unaudited; in millions)** | ** ** |
| ***ASSETS***                                                                                                |       |                                   |       |                        |       |   |   |
| Current assets                                                                                              |       |                                   |       |                        |       |   |   |
| Cash and cash equivalents (Note 5)                                                                          |       | $                                      | 82.4       |                        |       | $ | 78.3 |   |   |
| Receivables, trade and other, net of allowance for  doubtful accounts of $3.9 in 2005 and $4.0 in 2004 |       | 77.5                                   |       |                        | 71.7       |   |   |
| Due from General Partner and affiliates                                                                     |       | 21.5                                   |       |                        | 7.7        |   |   |
| Accrued receivables                                                                                         |       | 380.4                                  |       |                        | 378.2      |   |   |
| Inventory                                                                                                   |       | 91.6                                   |       |                        | 84.5       |   |   |
| Other current assets                                                                                        |       | 13.7                                   |       |                        | 13.4       |   |   |
|                                                                                                        |       | 667.1                                  |       |                        | 633.8      |   |   |
| Property, plant and equipment, net                                                                          |       | 3,061.3                                |       |                        | 2,778.0    |   |   |
| Other assets, net                                                                                           |       | 26.1                                   |       |                        | 27.7       |   |   |
| Goodwill                                                                                                    |       | 258.2                                  |       |                        | 257.2      |   |   |
| Intangibles, net                                                                                            |       | 86.5                                   |       |                        | 74.0       |   |   |
|                                                                                                        |       | $                                      | 4,099.2    |                        |       | $ | 3,770.7 |   |   |
| ***LIABILITIES AND PARTNERS’  CAPITAL***                                                               |       |                                   |       |                        |       |   |   |
| Current liabilities                                                                                         |       |                                   |       |                        |       |   |   |
| Due to General Partner and affiliates                                                                       |       | $                                      | 30.6       |                        |       | $ | 9.9 |   |   |
| Accounts payable and other (Note 5)                                                                         |       | 137.7                                  |       |                        | 136.4      |   |   |
| Accrued purchases                                                                                           |       | 368.3                                  |       |                        | 351.4      |   |   |
| Interest payable                                                                                            |       | 11.6                                   |       |                        | 12.3       |   |   |
| Property and other taxes payable                                                                            |       | 19.6                                   |       |                        | 23.3       |   |   |
| Current maturities of long-term debt                                                                        |       | 31.0                                   |       |                        | 31.0       |   |   |
|                                                                                                        |       | 598.8                                  |       |                        | 564.3      |   |   |
| Long-term debt                                                                                              |       | 1,773.9                                |       |                        | 1,559.4    |   |   |
| Loans from  General Partner and affiliates                                                                  |       | 146.9                                  |       |                        | 142.1      |   |   |
| Environmental  liabilities (Note 8)                                                                         |       | 5.0                                    |       |                        | 5.3        |   |   |
| Deferred credits                                                                                            |       | 185.0                                  |       |                        | 101.7      |   |   |
|                                                                                                        |       | 2,709.6                                |       |                        | 2,372.8    |   |   |
| Commitments and  contingencies (Note 8)                                                                     |       |                                   |       |                        |       |   |   |
| Partners’ capital                                                                                      |       |                                   |       |                        |       |   |   |
| Class A common units (Units issued—46,802,634  in 2005 and 44,296,134 in 2004)               |       | 1,083.2                                |       |                        | 1,021.6    |   |   |
| Class B common units (Units issued—3,912,750 in  2005 and 2004)                                   |       | 67.6                                   |       |                        | 66.7       |   |   |
| i-units (Units issued—11,306,254 in 2005 and  10,902,409 in 2004)                                      |       | 412.6                                  |       |                        | 399.4      |   |   |
| General Partner                                                                                             |       | 32.7                                   |       |                        | 31.0       |   |   |
| Accumulated other comprehensive loss                                                                        |       | (206.5                                 | )          |                        | (120.8     | ) |   |
|                                                                                                        |       | 1,389.6                                |       |                        | 1,397.9    |   |   |
|                                                                                                        |       | $                                      | 4,099.2    |                        |       | $ | 3,770.7 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**NOTESTO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)**

**1.   BASIS OF PRESENTATION**

The accompanying unauditedinterim consolidated financial statements have been prepared in accordance withaccounting principles generally accepted in the United States of America forinterim consolidated financial information and with the instructions to Form 10-Qand Rule 10-01 of Regulation S-X. Accordingly, they donot include all the information and footnotes required by accounting principlesgenerally accepted in the United States of America for complete consolidatedfinancial statements. In the opinion of management, they contain alladjustments, consisting only of normal recurring adjustments, which managementconsiders necessary to present fairly the financial position as of June 30,2005 and December 31, 2004; and the results of operations for the threeand six month periods ended June 30, 2005 and 2004; and cash flows for thesix month periods ended June 30, 2005 and 2004. The results of operationsfor the three and six months ended June 30, 2005, should not be taken asindicative of the results to be expected for the full year due to seasonalityof portions of the natural gas business, maintenance activities and the impactof forward natural gas prices on certain derivative financial instruments thatare accounted for using mark-to-market accounting. In addition,prior period information presented in these consolidated financial statementsincludes reclassifications that were made to conform to the current period presentation.These reclassifications have no effect on previously reported net income orpartners’ capital. The interim consolidated financial statements should be readin conjunction with our consolidated financial statements and notes presentedin our Annual Report on Form 10-K for the fiscal year ended December 31,2004.

**2.   ACQUISITIONS**

***North Texas Natural Gas System***

In January 2005,we acquired natural gas gathering and processing assets for $164.6 million incash, including transaction costs of $0.5 million. We funded the acquisitionwith borrowings under our existing credit facilities. The assets acquired servethe Fort Worth Basin, which is mature, but experiencing minimal productiondecline rates and include:

·       2,200miles of gas gathering pipelines; and

·       fourprocessing plants with aggregate processing capacity of 121 million cubic feetof natural gas per day (“MMcf/d”).

The system provides cash flow primarily frompurchasing raw natural gas from producers at the wellhead, processing the gasand then selling the natural gas liquids (“NGLs”) and residue gas streams. Theassets and results of operations are included in our Natural Gas segment fromthe date of acquisition.

The purchase price and theallocation to assets acquired and liabilities assumed was as follows (in millions):
| Purchase Price:                                                    |   |   |   |
|--------------------------------------------------------------------|--------|--------|--------|
| Cash paid, including transaction costs                             |   | $      | 164.6  |   |
| Allocation  of purchase price:                                     |   |   |   |
| Property, plant and equipment, including  construction in progress |   | 151.6  |   |
| Intangibles, including contracts                                   |   | 14.3   |   |
| Current liabilities                                                |   | (0.9   | )      |
| Contingent liabilities                                             |   | (0.4   | )      |
| Total                                                              |   | $      | 164.6  |   |

 

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***Other Acquisitions***

In June 2005, weacquired for $20.1 million in cash, a natural gas pipeline and relatedfacilities consisting of 92 miles of 20-inch diameter pipe that extends fromPampa, Texas into Western Oklahoma and has interconnects with our Anadarkosystem. We are integrating this pipeline into our existing Anadarko system andhave included the assets and operating results in our Natural Gas segment fromthe date of acquisition. The purchase price for this acquisition was allocatedto property, plant and equipment for $19.1 million and goodwill for $1.0million. We also acquired other gathering and processing assets forapproximately $1.2 million in cash.

**3.   NET INCOME PER COMMON AND i-UNIT**

Netincome per common and i-unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”)allocation, by the weighted average number of Class A and Class Bcommon units and i-units outstanding. The General Partner’s allocation isequal to an amount based upon its general partner interest, adjusted to reflectan amount equal to its incentive distributions and an amount required toreflect depreciation on the General Partner’s historical cost basis for assetscontributed on formation of the Partnership. There are no dilutive securities.Net income per common and i-unit was determined as follows:
| ** **                                            | ** ** | **Three months ended  June 30,**                     | ** ** | **Six months ended  June 30,**      | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                            | ** ** | **    2005   **                  | ** ** | **    2004   ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                            | ** ** | **(in millions, except per unit amounts)** | ** ** |
| Net income                                            |       |                                                                | $          | 25.7                                               |       |   |   | $ | 35.9 |   |   | $ | 53.9 |   | $ | 69.0 |   |
| Allocations to the General Partner:                   |       |                                                                |       |                                               |       |   |   |   |   |   |   |   |   |
| Net income allocated to General Partner               |       |                                                                | (0.5       | )                                                  |       |   | (0.7 | ) |   | (1.1 | ) | (1.4 | ) |
| Incentive distributions to General Partner            |       |                                                                | (5.3       | )                                                  |       |   | (4.8 | ) |   | (10.6 | ) | (9.5 | ) |
| Historical cost depreciation adjustments              |       |                                                                | —     |                                               |       |   | — |   |   | (0.1 | ) | (0.1 | ) |
|                                                  |       |                                                                | (5.8       | )                                                  |       |   | (5.5 | ) |   | (11.8 | ) | (11.0 | ) |
| Net income  allocable to common and i-units           |       |                                                                | $          | 19.9                                               |       |   |   | $ | 30.4 |   |   | $ | 42.1 |   | $ | 58.0 |   |
| Weighted average units outstanding                    |       |                                                                | 61.9       |                                               |       |   | 54.9 |   |   | 61.3 |   | 54.8 |   |
| Net income per  common and i-unit (basic and diluted) |       |                                                                | $          | 0.32                                               |       |   |   | $ | 0.56 |   |   | $ | 0.69 |   | $ | 1.06 |   |

 

**4.   FINANCIALINSTRUMENTS—COMMODITY PRICE RISK**

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, NGLs, condensate and fractionation margins (the relative pricedifferential between NGL sales and offsetting natural gas purchases). Thismarket price exposure exists within our Natural Gas and Marketing segments. Tomitigate the volatility of our cash flows, we use derivative financialinstruments (i.e., futures, forwards, swaps, options and other financialinstruments with similar characteristics) to manage the purchase and salesprices of the commodities. Based on our risk management policies, all of ourderivative financial instruments are employed in connection with an underlyingasset, liability and/or anticipated transaction and are not entered into withthe objective of speculating on commodity prices.

***Accounting Treatment***

All derivative financialinstruments are recorded in the consolidated financial statements at fairmarket value and are adjusted each period for changes in the fair market value(“mark-to-market”). Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),changes in the fair market value of derivatives that 

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qualifyas highly effective cash flow hedges are recorded as components of Accumulatedother comprehensive loss until the hedged transactions occur (“hedge accounting”).Hedge accounting can apply to either a hedge of future cash flows or the fairvalue of an asset or liability. Any ineffective portion of a cash flow hedge’schange in fair value is recognized each period in earnings. When the hedgedtransaction occurs, the fair value of the derivative is recognized in earnings,along with the offsetting fair value of the physical transaction. For thosederivative financial instruments that do not qualify for cash flow hedgeaccounting, the total change in fair value is recorded directly in earningseach period. Our preference, whenever possible, is for our derivative financialinstruments to receive hedge accounting treatment in order to mitigate thenoncash earnings volatility that arises under mark-to-marketaccounting treatment. However, to qualify for cash flow hedge accounting, veryspecific requirements must be met in terms of hedge structure, hedge objectiveand hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have three primary instances where the hedge structure does notmeet the requirements to apply hedge accounting and therefore, these financialinstruments are considered ‘non-qualified’ under SFAS No. 133. In theseinstances, the impacts of mark-to-market accounting for our non-qualifiedhedges are recorded in our Consolidated Statements of Income. Thesenon-qualified derivative financial instruments must be adjusted to their fairmarket value, or marked-to-market, each period, with the increasesand decreases in fair value recorded as increases and decreases in Cost ofnatural gas on our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often besignificant from period to period, but have no cash flow impact relative tochanges in market prices. The cash flow impact occurs when the underlyingphysical transaction takes place in the future and an associated financialinstrument contract settlement is made.

The three instancesof non-qualified hedges are as follows:

1.     In ourMarketing segment, when the pricing index used for gas sales is different fromthe pricing index used for gas purchases, we are exposed to relative changes inthose two indices. By entering into a basis swap between those two indices, wecan effectively lock in the margin on the combined gas purchase and gas sale,removing any market price risk on the physical transactions. Although thisrepresents a sound economic hedging strategy, these types of derivativetransactions do not qualify for hedge accounting under SFAS No. 133, asthe ultimate cash flow has not been fixed, only the margin.

2.     In ourMarketing segment, when we use derivative financial instruments to hedge marketspreads around our owned or contracted assets, such as our gas storageportfolio, the underlying forecasted transaction may or may not occur in thesame period as originally forecast. This can occur as we have the flexibilityto make these changes in the underlying injection or withdrawal schedule, givenchanges in market conditions. Therefore, these transactions do not qualify forhedge accounting treatment under SFAS No. 133, as the forecasted transactionis no longer probable of occurring as originally set forth in the hedgedocumentation.

3.     In our Natural Gas segment, we had previously entered intonatural gas collars in order to hedge the sales price of natural gas. Thenatural gas collars were based on a NYMEX price while the physical gas saleswere based on a different index. To better align the index of the natural gascollars with the index of the underlying sales, we de-designated theoriginal hedging relationship and contemporaneously re-designated thenatural gas collars as hedges of physical natural gas sales with a NYMEXpricing index to better match the indices. This is a sound economic hedgingstrategy, however, since these instruments were out of the money at re-designation,they are 

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considered netwritten options under SFAS No. 133. Therefore, these instruments do notqualify for hedge accounting upon re-designation and are now accountedfor in the Consolidated Statements of Income through mark-to-marketaccounting, with their changes in fair value from the date of de-designationrecorded to earnings each period. As a result, our operating income will besubject to greater volatility due to movements in the prices of natural gasuntil these underlying long-term transactions are settled.

***Discontinuance of Hedge Accounting***

During the second quarter of 2005, we discontinuedapplication of hedge accounting in connection with some of our derivativefinancial instruments designated as hedges of forecasted sales and purchases ofnatural gas. We discontinued application of hedge accounting when we determinedit was no longer probable that the originally forecasted purchases and sales ofnatural gas would occur by the end of the originally specified time period, orwithin an additional two-month period of time thereafter. One of the keycriteria to achieve hedge accounting under SFAS No. 133, is that theforecasted transaction is probable of occurring as originally documented in thehedge documentation. As a result, we recognized previously deferred unrealizedlosses in our Marketing segment of approximately $9.0 million from thediscontinuance of hedge accounting. In doing so, we reclassified the $9.0million to Cost of natural gas on our Consolidated Statements of income fromAccumulated other comprehensive income. Going forward, the discontinuedderivative financial instruments are considered to be non-qualified under SFAS No. 133,and must now be marked-to-market each period, with the increasesand decreases in fair value recorded as increases and decreases in earnings. Includedin the loss from discontinuance are approximately $2.1 million of netmark-to-market losses that relate to hedge positions that were closed-outduring the second quarter.

Thefollowing table presents the gains and losses associated with changes in thefair value of our derivatives which are recorded as an element of Cost ofnatural gas in our Consolidated Statements of Income and disclosed as areconciling item on our Statements of Cash Flows:
| ** **                                                   | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|--------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                      | ** ** | **   2005   **  | ** ** | **   2004   ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                          | ** ** |
| Natural Gas segment                                          |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                            | $          | (1.8                                          | )          |   |   | $ | — |   |   | $ | (2.0 | ) | $ | — |   |
| Non-qualified hedges                                         |       |                                            | (2.9       | )                                             |       |   | — |   |   | (11.1 | ) | — |   |
| Marketing                                                    |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                            | 3.9        |                                          |       |   | (1.9 | ) |   | 5.3 |   | (1.7 | ) |
| Discontinuance                                               |       |                                            | (9.0       | )                                             |       |   | — |   |   | (9.0 | ) | — |   |
| Derivative fair value  loss                                  |       |                                            | $          | (9.8                                          | )          |   |   | $ | (1.9 | ) |   | $ | (16.8 | ) | $ | (1.7 | ) |
|                                                              |            |                                                 |            |                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We record the change infair value of our highly effective cash flow hedges in our ConsolidatedStatements of Comprehensive Income until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. For the three andsix months ended June 30, 2005, we reclassified unrealized losses of $9.4million and $25.2 million from Accumulated other comprehensive loss to Cost ofnatural gas on our Consolidated Statements of Income for the fair value ofderivative financial instruments that were settled.

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Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:
| ** **                    | ** ** | **June 30,  2005** | ** ** | **December 31,  2004** | ** ** |
|-------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                    | ** ** | **(in millions)**  | ** ** |
| Receivables, trade and  other |       | $                       | 5.3        |                        |       | $ | 8.2 |   |   |
| Other assets, net             |       | 9.4                     |       |                        | 10.1       |   |   |
| Accounts payable and  other   |       | (60.8                   | )          |                        | (45.9      | ) |   |
| Deferred credits              |       | (182.5                  | )          |                        | (99.6      | ) |   |
|                          |       | $                       | (228.6     | )                           |       | $ | (127.2 | ) |   |

 

The increase in ourobligation associated with our derivative activities from December 31,2004 to June 30, 2005 is primarily due to the significant increases inforward natural gas and NGL prices. The Partnership’s portfolio of derivativefinancial instruments is largely comprised of long-term fixed price salesagreements.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments. All of our counterparties were rated “A” or better byall major credit rating agencies.

**5.   CASHAND CASH EQUIVALENTS**

We extinguish liabilitieswhen a creditor has relieved us of our obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. Accordingly, obligations for which we have issued check payments thathave not yet been presented to the financial institution of approximately$25.6 million at June 30, 2005 and $25.3 million at December 31,2004, are included in Accounts payable and other on the Consolidated Statementsof Financial Position.

**6.   DEBT**

***Amendment to CreditAgreement***

In April 2005, weentered into the third amendment to the Amended and Restated Credit Agreementdated as of January 24, 2003 (the “Credit Facility”) to, among otherthings, extend the maturity of the Credit Facility for a period of five yearsto April 2010; increase the letter of credit sublimit from$100 million to $175 million; and grant us the right to request,subject to approval by the Board of Directors of Enbridge Energy Management,L.L.C. (“Enbridge Management”), an increase in commitments available under theCredit Facility up to an aggregate outstanding principal amount of$1 billion. At June 30, 2005, our Credit Facility has no outstandingborrowings.

***Commercial PaperProgram***

In April 2005, wesuccessfully entered the commercial paper market with the establishment of our$600 million commercial paper program that is backstopped by our CreditFacility. We access the commercial paper market primarily to provide temporaryfinancing for our operating activities, capital expenditures and acquisitions,at rates that are generally lower than the rates available under our CreditFacility. We repaid the entire amount previously outstanding under our CreditFacility with proceeds we obtained from issuing commercial paper under thisprogram. Under the terms of our commercial paper program, we can issuecommercial paper up to the $600 million limit of our Credit Facility, reducedby the balance of outstanding Letters of Credit. At June 30, 2005, we hadoutstanding $390.0 million of commercial paper at a weighted average interestrate of 3.23% and outstanding Letters of Credit totaling $121.2 million. Availabilityunder our commercial paper program is $88.8 million at June 30, 2005.

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**7.   PARTNERS’CAPITAL**

Thefollowing table sets forth the distributions, as approved by the Board ofDirectors of Enbridge Management through June 30, 2005:
| **Distribution  Declaration  Date** | ** ** | **Distribution  Payment Date** | ** ** | **Ex-Distribution  Date** | ** ** | **Distribution  per Unit** | ** ** | **Cash  available for  distribution**                          | ** ** | **Amount of  Distribution  of i-units  to i-unit  Holders**(1) | ** ** | **Retained  from  General  Partner**(2) | ** ** | **Distribution  of Cash** | ** ** |
|-------------------------------------|------------|-------------------------------------|------------|---------------------------|------------|---------------------------------|------------|---------------------------------------------------------------------|------------|-------------------------------------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|
| ** **                          | ** ** | ** **                          | ** ** | ** **                | ** ** | ** **                      | ** ** | **(in millions, except per unit amounts)** | ** ** |
| April 25,  2005                |       | May 13, 2005                   |       | May 4, 2005          |       |                            | $          | 0.925                                                               |       |                                                                          |       | $                                       | 63.8       |                           |       |   | $ | 10.3 |   |   |   | $ | 0.2 |   |   |   | $ | 53.3 |   |   |
| January 24,  2005              |       | February 14, 2005              |       | February 3, 2005     |       |                            | 0.925      |                                                                |       |                                                                          | 61.0       |                                    |       |                           | 10.1       |   |   |   | 0.2 |   |   |   | 50.7 |   |   |
|                                |       |                                |       |                      |       |                            |       |                                                                |       |                                                                          | $          | 124.8                                   |       |                           |       | $ | 20.4 |   |   |   | $ | 0.4 |   |   |   | $ | 104.0 |   |   |

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(1)                 The Partnership has issued 403,845 i-unitsto Enbridge Management, the sole owner of the Partnership’s i-unitsduring 2005 in lieu of cash distributions.

(2)                 The Partnership retains an amount equal to2% of the i-unit distribution from the General Partner in respect of its2% general partner interest.

***Common unit offering***

On February 11, 2005,we issued 2,506,500 Class A common units at $49.875 per unit, whichgenerated proceeds of approximately $124.8 million, net of offeringexpenses. Additionally, the General Partner contributed $2.7 million to usto maintain its 2% general partner interest in the Partnership. We used theproceeds from this offering to repay amounts outstanding under our Credit Facility.

**8.   COMMITMENTS,CONTINGENCIES AND ENVIRONMENTAL LIABILITIES**

***Environmental Liabilities***

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to liquid and gas pipeline operations and we could, at times, besubject to environmental cleanup and enforcement actions. We manage thisenvironmental risk through appropriate environmental policies and practices tominimize any impact on the environment of our pipeline operations.

As of June 30, 2005and December 31, 2004, we have recorded $3.8 million and$3.6 million in current liabilities and $5.0 million and$5.3 million in long-term liabilities, respectively, primarily toaddress remediation of contaminated sites, asbestos containing materials,management of hazardous waste material disposal, and outstanding air qualitymeasures for certain liquids and natural gas assets.

***Legal Proceedings***

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethat the outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

**9.   SEGMENT INFORMATION**

Our business is divided into operating segments,defined as components of the enterprise, about which, financial information isavailable and evaluated regularly by our Chief Operating Decision Maker indeciding how resources are allocated and performance is assessed.

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Each of ourreportable segments is a business unit that offers different services andproducts that are managed separately since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·       Liquids;

·       NaturalGas; and

·       Marketing.

Thefollowing tables present certain financial information relating to our businesssegments:
| ** **                                    | ** ** | **As of and for the three months ended June 30, 2005** | ** ** |
|-----------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                    | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                 |       | $                                                                                                        | 102.5      |   |   | $ | 988.0 |   |   |   | $ | 802.1 |   |   |   | $ | — |   |   | $ | 1,892.6 |   |
| Less:  Intersegment revenue                   |       | —                                                                                                   |       |   | 526.7 |   |   |   | 33.2 |   |   |   | — |   |   | 559.9 |   |
| Operating revenue                             |       | 102.5                                                                                                    |       |   | 461.3 |   |   |   | 768.9 |   |   |   | — |   |   | 1,332.7 |   |
| Cost of natural  gas                          |       | —                                                                                                   |       |   | 379.5 |   |   |   | 770.9 |   |   |   | — |   |   | 1,150.4 |   |
| Operating and  administrative                 |       | 37.5                                                                                                     |       |   | 40.9 |   |   |   | 0.9 |   |   |   | 1.1 |   |   | 80.4 |   |
| Power                                         |       | 17.2                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 17.2 |   |
| Depreciation and  amortization                |       | 17.7                                                                                                     |       |   | 16.2 |   |   |   | 0.2 |   |   |   | — |   |   | 34.1 |   |
| Operating income                              |       | 30.1                                                                                                     |       |   | 24.7 |   |   |   | (3.1 | ) |   |   | (1.1 | ) |   | 50.6 |   |
| Interest expense                              |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | (25.6 | ) |   | (25.6 | ) |
| Other income                                  |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 0.7 |   |   | 0.7 |   |
| Net income                                    |       | $                                                                                                        | 30.1       |   |   | $ | 24.7 |   |   |   | $ | (3.1 | ) |   |   | $ | (26.0 | ) |   | $ | 25.7 |   |
| Capital expenditures (excluding acquisitions) |       | $                                                                                                        | 21.6       |   |   | $ | 78.6 |   |   |   | $ | — |   |   |   | $ | 1.6 |   |   | $ | 101.8 |   |

 
| ** **                                     | ** ** | **As of and for the three months ended June 30, 2004** | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                  |       | $                                                                                                        | 102.7      |   |   | $ | 630.4 |   |   |   | $ | 664.5 |   |   |   | $ | — |   |   | $ | 1,397.6 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                   |       |   | 395.5 |   |   |   | 32.4 |   |   |   | — |   |   | 427.9 |   |
| Operating revenue                              |       | 102.7                                                                                                    |       |   | 234.9 |   |   |   | 632.1 |   |   |   | — |   |   | 969.7 |   |
| Cost of natural  gas                           |       | —                                                                                                   |       |   | 166.9 |   |   |   | 630.6 |   |   |   | — |   |   | 797.5 |   |
| Operating and  administrative                  |       | 33.4                                                                                                     |       |   | 33.3 |   |   |   | 0.8 |   |   |   | 0.7 |   |   | 68.2 |   |
| Power                                          |       | 17.1                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 17.1 |   |
| Depreciation and  amortization                 |       | 16.8                                                                                                     |       |   | 12.1 |   |   |   | — |   |   |   | — |   |   | 28.9 |   |
| Operating income                               |       | 35.4                                                                                                     |       |   | 22.6 |   |   |   | 0.7 |   |   |   | (0.7 | ) |   | 58.0 |   |
| Interest expense                               |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | (22.0 | ) |   | (22.0 | ) |
| Other expense                                  |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | (0.1 | ) |   | (0.1 | ) |
| Net income                                     |       | $                                                                                                        | 35.4       |   |   | $ | 22.6 |   |   |   | $ | 0.7 |   |   |   | $ | (22.8 | ) |   | $ | 35.9 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                        | 18.9       |   |   | $ | 29.4 |   |   |   | $ | — |   |   |   | $ | 0.9 |   |   | $ | 49.2 |   |

 

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| ** **                                    | ** ** | **As of and for the six months ended June 30, 2005** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                    | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | ** Marketing ** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                 |       | $                                                                                                      | 199.0      |   |   | $ | 1,912.6 |   |   |   | $ | 1,495.9 |   |   |   | $ | — |   |   | $ | 3,607.5 |   |
| Less:  Intersegment revenue                   |       | —                                                                                                 |       |   | 965.7 |   |   |   | 59.0 |   |   |   | — |   |   | 1,024.7 |   |
| Operating revenue                             |       | 199.0                                                                                                  |       |   | 946.9 |   |   |   | 1,436.9 |   |   |   | — |   |   | 2,582.8 |   |
| Cost of natural  gas                          |       | —                                                                                                 |       |   | 786.0 |   |   |   | 1,436.6 |   |   |   | — |   |   | 2,222.6 |   |
| Operating and  administrative                 |       | 69.4                                                                                                   |       |   | 82.0 |   |   |   | 1.7 |   |   |   | 1.7 |   |   | 154.8 |   |
| Power                                         |       | 34.2                                                                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   | 34.2 |   |
| Depreciation and  amortization                |       | 35.3                                                                                                   |       |   | 31.8 |   |   |   | 0.3 |   |   |   | — |   |   | 67.4 |   |
| Operating income                              |       | 60.1                                                                                                   |       |   | 47.1 |   |   |   | (1.7 | ) |   |   | (1.7 | ) |   | 103.8 |   |
| Interest expense                              |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | (51.2 | ) |   | (51.2 | ) |
| Other income                                  |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 1.3 |   |   | 1.3 |   |
| Net income                                    |       | $                                                                                                      | 60.1       |   |   | $ | 47.1 |   |   |   | $ | (1.7 | ) |   |   | $ | (51.6 | ) |   | $ | 53.9 |   |
| Total assets                                  |       | $                                                                                                      | 1,670.8    |   |   | $ | 2,053.3 |   |   |   | $ | 280.6 |   |   |   | $ | 94.5 |   |   | $ | 4,099.2 |   |
| Goodwill                                      |       | $                                                                                                      | —     |   |   | $ | 237.8 |   |   |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 258.2 |   |
| Capital expenditures (excluding acquisitions) |       | $                                                                                                      | 34.7       |   |   | $ | 137.3 |   |   |   | $ | — |   |   |   | $ | 2.7 |   |   | $ | 174.7 |   |

 
| ** **                                     | ** ** | **As of and for the six months ended June 30, 2004** | ** ** |
|------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | ** Marketing ** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                  |       | $                                                                                                      | 194.4      |   |   | $ | 1,294.9 |   |   |   | $ | 1,261.4 |   |   |   | $ | — |   |   | $ | 2,750.7 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                 |       |   | 725.3 |   |   |   | 73.2 |   |   |   | — |   |   | 798.5 |   |
| Operating revenue                              |       | 194.4                                                                                                  |       |   | 569.6 |   |   |   | 1,188.2 |   |   |   | — |   |   | 1,952.2 |   |
| Cost of natural  gas                           |       | —                                                                                                 |       |   | 435.6 |   |   |   | 1,183.7 |   |   |   | — |   |   | 1,619.3 |   |
| Operating and  administrative                  |       | 61.2                                                                                                   |       |   | 65.7 |   |   |   | 1.6 |   |   |   | 2.0 |   |   | 130.5 |   |
| Power                                          |       | 34.3                                                                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   | 34.3 |   |
| Depreciation and  amortization                 |       | 32.9                                                                                                   |       |   | 24.6 |   |   |   | — |   |   |   | — |   |   | 57.5 |   |
| Operating income                               |       | 66.0                                                                                                   |       |   | 43.7 |   |   |   | 2.9 |   |   |   | (2.0 | ) |   | 110.6 |   |
| Interest expense                               |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | (43.6 | ) |   | (43.6 | ) |
| Other income                                   |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 2.0 |   |   | 2.0 |   |
| Net income                                     |       | $                                                                                                      | 66.0       |   |   | $ | 43.7 |   |   |   | $ | 2.9 |   |   |   | $ | (43.6 | ) |   | $ | 69.0 |   |
| Total assets                                   |       | $                                                                                                      | 1,638.9    |   |   | $ | 1,522.9 |   |   |   | $ | 277.8 |   |   |   | $ | 28.5 |   |   | $ | 3,468.1 |   |
| Goodwill                                       |       | $                                                                                                      | —     |   |   | $ | 237.0 |   |   |   | $ | 20.3 |   |   |   | $ | — |   |   | $ | 257.3 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                      | 26.8       |   |   | $ | 42.7 |   |   |   | $ | — |   |   |   | $ | 1.3 |   |   | $ | 70.8 |   |

 

**10.   SUBSEQUENT EVENTS**

***Distribution to Partners***

On July 28, 2005,Enbridge Management’s Board of Directors declared a distribution payable to ourpartners on August 12, 2005. The distribution will be paid to unitholdersof record as of August 5, 2005, of our available cash of$64.0 million at June 30, 2005, or $0.925 per common unit. Of thisdistribution, 

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$53.3 millionwill be paid in cash, $10.5 million will be distributed in i-unitsto our i-unitholder and $0.2 million will be retained from theGeneral Partner in respect of this i-unit distribution.

**11.   RECENTACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED**

***Accounting for Conditional Asset RetirementObligations***

In March 2005, theFinancial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47,*Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143*. Thisinterpretation clarifies the meaning of “conditional asset retirementobligation” as used in FASB Statement No. 143, *Accounting for Asset Retirement Obligations* as referring toa legal obligation to perform an asset retirement activity where the timingand/or method of settlement are conditional on a future event that may or maynot be within the control of an entity. The obligation to perform theretirement activity is unconditional even though uncertainty may exist aboutthe timing and/or method of settlement. The interpretation requires an entityto recognize a liability for the fair value of a conditional asset retirementobligation if the fair value of the liability can be reasonably estimated. Thisinterpretation is effective no later than the end of fiscal years ending after December 15,2005. We are currently evaluating the effect that application of thisinterpretation will have on our financial statements.

***Accounting Changes and Error Corrections***

In May 2005, the FASBissued Statement of Financial Accounting Standards No. 154, *Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20and FASB Statement No. 3*. Under this statement, voluntarychanges in accounting principle are required to be applied retrospectively forthe direct effects of a change to prior periods’ financial statements, unlesssuch application is impracticable. Retrospective application refers toreflecting a change in accounting principle in the financial statements ofprior periods as if the principle had always been used. When retrospectiveapplication is determined to be impracticable, this statement requires the newaccounting principle to be applied to the balances of assets and liabilities asof the beginning of the earliest period for which retrospective treatment ispracticable with a corresponding adjustment to the opening balance of retainedearnings. This statement retains the guidance in APB Opinion No. 20 forreporting the corrections of errors and changes in accounting estimates. Thisstatement is effective for accounting changes and corrections of errors made infiscal years beginning after December 15, 2005, with early adoptionpermitted. Our adoption of this statement will effect our consolidatedfinancial statements for any changes in accounting principle we may make in thefuture, or new pronouncements we adopt that do not provide transitionprovisions.

***FERC Guidance on Accounting for Integrity ManagementCosts***

In June 2005, the Federal Energy RegulatoryCommission (“FERC”) issued guidance describing how FERC-regulated companiesshould account for costs associated with implementing the pipeline integritymanagement requirements of the U.S. Department of Transportation’s Office ofPipeline Safety. Under the guidance, costs to 1) prepare a plan to implementthe program, 2) identify high consequence areas, 3) develop and maintain arecord keeping system and 4) inspect, test and report on the condition ofaffected pipeline segments to determine the need for repairs or replacements,are required to be expensed. Costs of modifying pipelines to permit in-lineinspections, certain costs associated with developing or enhancing computersoftware and costs associated with remedial and mitigation actions to correctan identified condition can be capitalized. The guidance is effective January 1,2006, to be applied prospectively. We are currently evaluating the effect thatapplication of this order will have on our financial statements.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

**RESULTS OF OPERATIONS—OVERVIEW**

We provide servicesto our customers and create value for our unitholders primarily through thefollowing activities:

·       Interstatetransportation and storage of crude oil and liquid petroleum;

·       Gathering,treating, processing and transmission of natural gas; and

·       Providingsupply, transmission and sales service, including purchasing and sellingnatural gas and natural gas liquids (“NGLs”).

We primarily provide fee-based services to ourcustomers to minimize commodity price risks. However, in our natural gas andmarketing businesses, a portion of our earnings and cash flows are exposed tomovements in the prices of natural gas and NGLs. To substantially mitigate thisexposure, we enter into derivative financial instrument transactions. Certainof these transactions qualify for hedge accounting under Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),some however, must be accounted for using the mark-to-market methodof accounting.

We conduct our business through three businesssegments: Liquids, Natural Gas and Marketing. These segments are strategic businessunits established by senior management to facilitate the achievement of ourlong-term objectives, to aid in resource allocation decisions and toassess operational performance.

Thefollowing table reflects operating income by business segment and corporatecharges for each of the periods presented.
| ** **                              | ** ** | **Three months ended  June 30,**          | ** ** | **Six months ended  June 30,**            | ** ** |
|-----------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                              | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** | **   2005   ** | ** ** | **   2004   ** | ** ** |
| ** **                              | ** ** | **(unaudited; in millions)**                   | ** ** |
| **Operating Income**                    |       |                                                     |       |                                                     |       |   |   |   |   |   |   |   |   |
| Liquids                                 |       |                                                     | $          | 30.1                                                     |       |   |   | $ | 35.4 |   |   | $ | 60.1 |   | $ | 66.0 |   |
| Natural Gas                             |       |                                                     | 24.7       |                                                     |       |   | 22.6 |   |   | 47.1 |   | 43.7 |   |
| Marketing                               |       |                                                     | (3.1       | )                                                        |       |   | 0.7 |   |   | (1.7 | ) | 2.9 |   |
| Corporate, operating and administrative |       |                                                     | (1.1       | )                                                        |       |   | (0.7 | ) |   | (1.7 | ) | (2.0 | ) |
| **Total Operating Income**              |       |                                                     | 50.6       |                                                     |       |   | 58.0 |   |   | 103.8 |   | 110.6 |   |
| Interest expense                        |       |                                                     | (25.6      | )                                                        |       |   | (22.0 | ) |   | (51.2 | ) | (43.6 | ) |
| Other income                            |       |                                                     | 0.7        |                                                     |       |   | (0.1 | ) |   | 1.3 |   | 2.0 |   |
| **Net  Income**                         |       |                                                     | $          | 25.7                                                     |       |   |   | $ | 35.9 |   |   | $ | 53.9 |   | $ | 69.0 |   |

 

Consolidated net income for the three and six monthsended June 30, 2005, was $25.7 million and $53.9 million comparedwith $35.9 million and $69.0 million for the same periods of 2004. Thedecrease in net income is attributable to lower transportation volumes on ourLiquids segment, non-cash mark-to-market losses of $9.8 million and $16.8million from derivative transactions in our Natural Gas and Marketing segmentsfor the respective periods, as well as higher interest expense. The decreases inour net income were partially offset by increased volumes in our Natural Gassegment coupled with increases in natural gas and NGL prices.

Earnings per unit decreased to $0.32 per unit and$0.69 per unit for the three and six months ended June 30, 2005,representing declines from the $0.56 per unit and $1.06 per unit we reportedfor the comparable periods in 2004. Earnings per unit were lower for the secondquarter of 2005 due to the decrease in net income and an increase in the numberof common units outstanding. Since the second 

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quarter of 2004, we have issued6,186,500 Class A common units and 848,833 i-units that haveincreased the weighted average number of our common units outstanding to 61.9million and 61.3 million for the three and six months ended June 30, 2005,from 54.9 million and 54.8 million for the same periods in 2004.

We acquired natural gas gatheringand processing assets in North Texas in January 2005. The facilitiesacquired include approximately 2,200 miles of natural gas gatheringpipelines and four natural gas processing plants with an aggregate processingcapacity of 121 million cubic feet per day (“MMcf/d”) of natural gas. Thissystem predominantly serves producers in the Fort Worth Basin Conglomerateformation and is located in an area where we expect future drilling byproducers extending the Barnett Shale play’s western flank. We combined theseassets with our existing North Texas assets and have included them in theoperating results of our Natural Gas segment from the date of acquisition. Inlate June 2005, we also acquired an idle 92 mile natural gas pipelinethat extends from the Texas Panhandle to Western Oklahoma which we areintegrating with our existing Anadarko system. Although this pipeline did notcontribute to our operating results for the quarter and six months ended June 30,2005, we expect this pipeline to improve service to existing customers andallow us to attract additional production in future periods.

**RESULTS OF OPERATIONS—BY SEGMENT**

***Liquids***

Thefollowing tables sets forth the operating results and statistics of our Liquidssegment assets for the periods presented:
| ** **                     | ** ** | **Three months ended  June 30,**                      | ** ** | **Six months ended  June 30,**                        | ** ** |
|--------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                     | ** ** | **     2005     ** | ** ** | **     2004     ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**                               | ** ** |
| **Operating  Results**         | ** ** |                                                                 | ** ** | ** **                                                           |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Operating  revenues            |       |                                                                 | $          | 102.5                                                                | ** ** |   |   | $ | 102.7 | ** ** |   | $ | 199.0 |   | $ | 194.4 |   |
| Operating and  administrative  |       |                                                                 | (37.5      | )                                                                    |       |   | (33.4 | ) |   | (69.4 | ) | (61.2 | ) |
| Power                          |       |                                                                 | (17.2      | )                                                                    |       |   | (17.1 | ) |   | (34.2 | ) | (34.3 | ) |
| Depreciation and  amortization |       |                                                                 | (17.7      | )                                                                    |       |   | (16.8 | ) |   | (35.3 | ) | (32.9 | ) |
| Expenses                       |       |                                                                 | (72.4      | )                                                                    |       |   | (67.3 | ) |   | (138.9 | ) | (128.4 | ) |
| **Operating  Income**          |       |                                                                 | $          | 30.1                                                                 |       |   |   | $ | 35.4 |   |   | $ | 60.1 |   | $ | 66.0 |   |

 
| ** **                              | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------|------------|------------|------------|------------|
| **Operating  Statistics**               | ** ** |       | ** ** | ** ** |   |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **Lakehead  system:**                   |       |       |       | ** ** |   |   |   | ** ** |   |   |   |   |   |
| United States(1)                        |       |       | 1,052      | ** ** |   |   | 1,103 | ** ** |   | 1,031 |   | 1,059 |   |
| Province of Ontario(1)                  |       |       | 277        | ** ** |   |   | 355 | ** ** |   | 302 |   | 373 |   |
| **Total deliveries**(1)                 |       |       | 1,329      | ** ** |   |   | 1,458 | ** ** |   | 1,333 |   | 1,432 |   |
| **Barrel miles (billions)**             |       |       | 84         | ** ** |   |   | 92 | ** ** |   | 167 |   | 182 |   |
| **Average haul (miles)**                |       |       | 692        | ** ** |   |   | 697 | ** ** |   | 691 |   | 700 |   |
| **Mid-Continent  system deliveries**(1) |       |       | 226        | ** ** |   |   | 205 | ** ** |   | 208 |   | 214 |   |
| **North Dakota system deliveries**(1)   |       |       | 89         | ** ** |   |   | 85 | ** ** |   | 89 |   | 79 |   |

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(1)     Averagebarrels per day (“Bpd”) in thousands.

***Three months ended June 30, 2005 compared withthree months ended June 30, 2004***

Our Liquids segment accounted for $30.1 millionof operating income, or 59% of consolidated operating income in the secondquarter of 2005. This was a decrease of $5.3 million in operating income 

17

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over the same period in2004. Lower results on the Lakehead and Mid-Continent systems were slightlyoffset by stronger results on the North Dakota system.

Operating revenue for the second quarter of 2005 wasconsistent with the same period in 2004. Overall tariff increases, higherdeliveries on our Mid-Continent and North Dakota systems, and longer hauls onour North Dakota system, were more than offset by lower results on the Lakeheadsystem.

Increases in average tariffs on all three Liquidssystems resulted in higher operating revenue by approximately $6.2 million. Thesetariff increases were mostly the result of the annual index rate increase ofapproximately 3.17% allowed by the Federal Energy Regulatory Commission (“FERC”)effective July 1, 2004 and the Terrace and Facilities Surcharges on theLakehead system, that were not in effect during the second quarter of 2004. Longerhauls on our North Dakota system also contributed to a higher average tariff,as production in Montana has been strong.

Volumes on the Lakehead system decreased approximately9%, from 1.458 million Bpd during the second quarter of 2004 to 1.329million Bpd during the same period in 2005. This resulted in lower operatingrevenue of approximately $7.9 million. The decrease is primarily theresult of lower than expected supply in Western Canada from Suncor, an oilsands producer in Alberta, Canada. On January 4, 2005, a fire occurred attheir upgrader site and since that time, production has been reduced by anaverage of 90,000 Bpd compared to the same period in 2004. Suncor has statedthat plans are to return to full production capacity in September 2005. Untilthat time, we expect deliveries on the Lakehead system to be negativelyimpacted by the decreased Suncor production. Western Canadian crude oil supplyavailable for delivery on our Lakehead system was also reduced during thesecond quarter of 2005, compared to the same period in 2004, due to timingdifferences. Bitumen production was lower during the second quarter of 2005, asthe nature of the cyclic steaming process used to extract it from the groundcan cause production timing differences during the year. Also, refineryturnarounds in Alberta that took place in 2004 did not recur in the secondquarter of 2005, thereby lowering the amount of crude oil available fordelivery on the Lakehead system in 2005. Finally, during the second quarter of2005, Terasen Inc., operator of the Express Pipeline which transports westernCanadian crude to the U.S. Rocky Mountain market, completed an expansion ontheir Express Pipeline. This expansion increased capacity on their pipeline byapproximately 108,000 Bpd. Given the volume commitments on the Express Pipelineexpansion, coupled with the lower western Canadian crude oil supply as notedabove, deliveries on our Lakehead system were negatively impacted during thesecond quarter of 2005. Holders of firm capacity on the Express Pipeline willfirst satisfy their commitments to that pipeline before moving incrementalbarrels on the Lakehead system.

Operating andadministrative expenses for the Liquids segment increased $4.1 million or 12%in the second quarter of 2005, compared with the same period in 2004. Capitalproject recoveries are lower by approximately $1.4 million due to a decrease inutilization of our workforce on capital projects and a reduction inconstruction activity on our Lakehead system. Pipeline integrity work hasincreased on the Lakehead system during the second quarter of 2005, whichresulted in higher operating costs of approximately $1.1 million. Oilmeasurement losses on the Lakehead system were higher in the second quarter of2005 by approximately $0.8 million, primarily due to higher oil prices andwider light/heavy crude price differentials (see further explanation below inthe six month analysis).

***Six months ended June 30, 2005 compared to sixmonths ended June 30, 2004***

Our Liquids segment accounted for $60.1 million, or58%, of consolidated operating income in the first half of 2005. This was adecrease of $5.9 million in operating income over the same period in 2004. Operating income decreased in 2005 for the samereason as noted above in the three-month analysis.

Operating revenue for the first six months of 2005increased by $4.6 million to $199.0 million, compared with$194.4 million for the same period in 2004. The increase in averagetariffs on all Liquids 

18

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systems resulted in higheroperating revenue of approximately $10.4 million for the reasons noted above inthe three-month analysis. In 2005, our Mid-Continent assets contributed for afull six-month period compared to four months in 2004, which resulted in higheroperating revenue of approximately $7.8 million. These increases weremostly offset by lower deliveries on the Lakehead system for the same reason asnoted above in the three-month analysis. This resulted in a decrease ofapproximately $13.1 million in operating revenue in the second quarter of 2005.

Operating and administrative expenses for the firstsix months of 2005 increased by $8.2 million to $69.4 million,compared with $61.2 million for the same period in 2004. The increase isdriven primarily from higher oil measurement losses of approximately $5.4 onthe Lakehead system for the six-month period.

Oil measurementlosses occur as part of the normal operating conditions associated with ourLiquids pipelines. The three types of oil measurement losses include:

·       physicallosses, which occur through evaporation, shrinkage, differences in measurementbetween receipt and delivery locations and other operational incidents;

·       degradationlosses, which result from mixing at the interface between higher quality lightcrude oil and lower quality heavy crude oil in pipelines; and

·       revaluationlosses, which are a function of crude oil prices, the level of the carrier’sinventory and the inventory positions of customers.

During the six months ended June 30, 2005, theincrease in oil measurement losses was a function of three factors:

1.                Higher volumetricphysical losses associated with changes in commodity properties andmeasurement, coupled with higher oil prices that made the absolute value ofeven normal physical losses more expensive. During the first six months of2005, the average West Texas Intermediate crude oil price was approximately $51per barrel compared with approximately $36 per barrel during the sameperiod in 2004;

2.                Wider light/heavycrude price differentials made degradation losses more expensive. During thefirst six months of 2005, light/heavy differentials were approximately $20 perbarrel compared with approximately $11 per barrel in 2004; and

3.                Limitedmarket liquidity is available to settle specific crude oil positions that arenaturally created by our pipeline system’s operations. Market liquidity isespecially constrained when a price trend is anticipated by crude oilmarketers. As a result, we carried net short positions that we could notphysically settle during the first six months of 2005, on which we experienceda loss prior to settling the position.

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***Natural Gas***

Thefollowing tables sets forth the operating results of our Natural Gas segmentassets and average daily volumes of our major systems in millions of BritishThermal units per day (“MMBtu/d”) for the periods presented:
| ** **                     | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|--------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                     | ** ** | **2005**                                        | ** ** | **2004**                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**          | ** ** |
| **Operating Results**          |       |                                            |       |                                          |       |   |   |   |   |
| Operating  revenues            |       | $                                               | 461.3      |                                          | $          | 234.9 |   | $ | 946.9 |   | $ | 569.6 |   |
| Cost of natural  gas           |       | (379.5                                          | )          | (166.9                                        | )          | (786.0 | ) | (435.6 | ) |
| Operating and  administrative  |       | (40.9                                           | )          | (33.3                                         | )          | (82.0 | ) | (65.7 | ) |
| Depreciation and  amortization |       | (16.2                                           | )          | (12.1                                         | )          | (31.8 | ) | (24.6 | ) |
| Expenses                       |       | (436.6                                          | )          | (212.3                                        | )          | (899.8 | ) | (525.9 | ) |
| **Operating  Income**          |       | $                                               | 24.7       |                                          | $          | 22.6 |   | $ | 47.1 |   | $ | 43.7 |   |

 
| **Operating Statistics (MMBtu/d)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| East Texas                         |       | 833,000    |       | 655,000    |       | 810,000    |       | 619,000    |       |
| Anadarko(1)                        |       | 478,000    |       | 332,000    |       | 465,000    |       | 308,000    |       |
| North Texas                        |       | 260,000    |       | 188,000    |       | 262,000    |       | 190,000    |       |
| South Texas                        |       | 34,000     |       | 42,000     |       | 36,000     |       | 43,000     |       |
| UTOS                               |       | 191,000    |       | 218,000    |       | 194,000    |       | 212,000    |       |
| MidLa                              |       | 107,000    |       | 97,000     |       | 106,000    |       | 107,000    |       |
| AlaTenn                            |       | 53,000     |       | 54,000     |       | 68,000     |       | 67,000     |       |
| KPC                                |       | 19,000     |       | 27,000     |       | 39,000     |       | 58,000     |       |
| Bamagas                            |       | 9,000      |       | 35,000     |       | 11,000     |       | 22,000     |       |
| Other Major  Intrastates(1)        |       | 209,000    |       | 167,000    |       | 215,000    |       | 176,000    |       |
| Total                              |       | 2,193,000  |       | 1,815,000  |       | 2,206,000  |       | 1,802,000  |       |

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(1)                 Anadarkoincludes the combined systems previously referred to separately as Anadarko andPalo Duro. The Palo Duro volumes were formerly included with Other MajorIntrastates.

***Three months ended June 30, 2005 compared withthree months ended June 30, 2004***

Our Natural Gas segment accounted for$24.7 million of operating income, or 49%, of consolidated operating incomein the second quarter of 2005. This was an increase of $2.1 million inoperating income over the corresponding period in 2004.

Average daily volumes on our major natural gas systemsincreased 21% in the second quarter of 2005, compared with the correspondingperiod in 2004. The increase in volumes is primarily the result of additionalwellhead supply contracts on our East Texas and Anadarko systems as well as theadditional volumes on the North Texas system associated with the acquisition ofadditional gathering and processing assets in January 2005. We expectvolumes in these areas to continue to increase as a result of increaseddrilling activity in the Anadarko basin, the Bossier trend and the BarnettShale area. Additionally, we anticipate transportation volumes to furtherincrease on our East Texas system as a result of completing the 500 MMcf/dsystem expansion in late June 2005.

A portion of our Natural Gas segment is exposed tocommodity price risks associated with percent of proceeds or percentage ofindex contracts that we negotiate with producers. Under the terms of thesecontracts, we retain a portion of the natural gas and NGLs we process inexchange for providing these 

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producers with ourservices. In order to protect our unitholders from the volatility in cash flowsthat can result from fluctuations in commodity prices, we enter into derivativefinancial instruments to fix the sales price of the natural gas and NGLs weanticipate receiving under the terms of these contracts. As a result of enteringinto these derivative financial instruments, we have largely fixed the amountof cash that we will receive at the time we sell the processed natural gas andNGLs, although the market price of these commodities will continue tofluctuate. The remainder of the revenue we receive is derived from fees chargedfor gathering and treating of natural gas volumes and other related services.

A relatively small, but variable element of theNatural Gas segment’s operating income is derived from keep-whole processingof natural gas. This contract structure requires us to process natural gas attimes when it may not be economical to do so. This can happen when natural gasprices are unusually high or NGL prices are unusually low. During the secondquarter of 2005, although natural gas prices were unusually high, they weremore than offset by favorable NGL prices. Operating revenue less cost ofnatural gas derived from keep-whole processing for the three months endedJune 30, 2005, was approximately $6.4 million compared with$0.9 million for the same period in 2004.

The positive growth in our natural gas and NGLgathering, processing and transportation volumes for the second quarter of 2005was partially offset by increases in operating costs that are mostly variablewith volumes. The higher volumes on the systems resulted in increases ofworkforce related costs approximating $1.4 million, and repair and maintenancecosts of approximately $1.1 million. Operating costs were also higher in 2005by $1.5 million of incremental costs associated with the natural gas gatheringand processing assets we acquired in January 2005.

We included mark-to-marketlosses of $4.7 million in the Cost of natural gas, of which $1.8 millionis due to ineffectiveness on our qualified cash flow hedges and $2.9 million isattributable to certain derivative financial instruments that do not qualifyfor hedge accounting treatment under SFAS No. 133 (refer also to thediscussions included below under Derivative Transactions, Note 4 of Item 1.Financial Statements, and Item 3. Quantitative and Qualitative DisclosuresAbout Market Risk). Although changes in the fair value of these specificderivative financial instruments do not affect our cash flow, we anticipate thesechanges will continue to create volatility in our Consolidated Statements of Incomegoing forward due to the inherent volatility of natural gas and NGL prices.

***Six months ended June 30, 2005 compared with sixmonths ended June 30, 2004***

Our Natural Gas segment accounted for$47.1 million of consolidated operating income for the six monthsended June 30, 2005, an increase of 8% over the $43.7 million for the sameperiod of 2004.

Average daily volumes on our major natural gas systemsincreased 22%, or 404,000 MMBtu/d, for the first half of 2005, compared withthe corresponding period in 2004. The increase in volumes is primarilyattributable to additional wellhead supply contracts on our East Texas andAnadarko systems, as well as the additional volumes on the North Texas systemassociated with the acquisition of additional gathering and processing assetsin January 2005.

As previously noted under our three month analysis, aportion of our Natural Gas segment’s operating income is derived fromprocessing of natural gas under keep-whole arrangements. Operating revenue lesscost of natural gas derived from keep-whole processing for the six monthsended June 30, 2005, was approximately $10.5 million compared with$3.0 million for the same period in 2004.

Operating and administrative costs associated with ourNatural Gas segment were $16.3 million greater for the six months ended June 30,2005 over the same period of 2004. Approximately $3.2 million of the increaseis attributable to the natural gas gathering and processing assets we acquiredin January 2005. The down time for maintenance activities at three of ourprocessing plants along with the $1.6 million we spent performing thismaintenance also contributed to the increase. The remaining 

21

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increase is primarily dueto workforce related costs of $5.4 million attributable to additional personneland associated benefit costs related to the volume growth on our systems.

Operating income from ourNatural Gas segment during the six months ended June 30, 2005 was negativelyaffected by noncash losses from derivative transactions of $13.1 million,recorded in the Cost of natural gas. The losses consist of $11.1 million ofmark-to-market adjustments on derivative financial instruments that do notqualify for hedge accounting treatment under SFAS No. 133 and $2.0 millionof losses recognized for the ineffective portion of derivative financialinstruments designated as cash flow hedges of natural gas purchase and salestransactions (refer also to the discussions included below under DerivativeTransactions, Note 4 of Item 1. Financial Statements, and Item 3. Quantitativeand Qualitative Disclosures About Market Risk). Although changes in the fairvalue of these specific derivative financial instruments do not affect our cashflow, we anticipate changes in the fair value of these contracts will continueto create volatility in our Consolidated Statements of Income going forward dueto the inherent volatility of the natural gas and NGL prices.

***Marketing***

The following table setsforth the operating results for the Marketing segment assets for the periodspresented:
| ** **                     | ** ** | **Three months ended  June 30,**                                                          | ** ** | **Six months ended  June 30,**                                                            | ** ** |
|--------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                     | ** ** | **        2005        ** | ** ** | **        2004        ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**                                                                   | ** ** |
| Operating revenues             |       |                                                                                                     | $          | 768.9                                                                                                    |       |   |   | $ | 632.1 |   |   | $ | 1,436.9 |   | $ | 1,188.2 |   |
| Cost of natural  gas           |       |                                                                                                     | (770.9     | )                                                                                                        |       |   | (630.6 | ) |   | (1,436.6 | ) | (1,183.7 | ) |
| Operating and  administrative  |       |                                                                                                     | (0.9       | )                                                                                                        |       |   | (0.8 | ) |   | (1.7 | ) | (1.6 | ) |
| Depreciation and  amortization |       |                                                                                                     | (0.2       | )                                                                                                        |       |   | — |   |   | (0.3 | ) | — |   |
| Expenses                       |       |                                                                                                     | (772.0     | )                                                                                                        |       |   | (631.4 | ) |   | (1,438.6 | ) | (1,185.3 | ) |
| **Operating Income (loss)**    |       |                                                                                                     | $          | (3.1                                                                                                     | )          |   |   | $ | 0.7 |   |   | $ | (1.7 | ) | $ | 2.9 |   |

 

***Three months ended June 30, 2005 compared withthree months ended June 30, 2004***

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from customers on ourNatural Gas segment pipeline assets to end users of natural gas. A majority ofthe natural gas is purchased in Texas markets where we have limited physicalaccess to the primary pricing points, or Hubs, such as WAHA and the HoustonShip Channel. As a result, our Marketing business must rely on third-partypipelines to transport the natural gas to the markets where it can be sold toend users. Wherever possible, our Marketing business will sell gas into theseliquid market points. However, physical pipeline constraints often require ourMarketing business to take natural gas to alternate market points. This createsprice exposure for the relative difference in natural gas prices between thecontracted index at which the natural gas is purchased and the index underwhich it is sold. The difference between the prices at which the natural gas ispurchased and the prices at which it is sold can be significant due to supplyand demand factors at locations where the natural gas is purchased and sold. Whereverpossible, this pricing exposure is hedged using derivative financialinstruments.

Our Marketing segment continues to be impacted bylower unit margins on natural gas volumes purchased due to physical pipelineconstraints. The recent completion of our East Texas system expansion haspartially alleviated these constraints; however, increasing production volumeswill continue to create additional constraints, which will require continueduse of third-party pipelines in East Texas. This situation is not limited tothe East Texas region. Pricing in our natural gas supply markets is expected tocontinue to experience increasing pressure due to more natural gas suppliesfrom the Rocky Mountains 

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and North Texas. For thisreason we have increased our commitments on third-party pipelines toprovide more attractive market outlets for our natural gas supply. However,there continues to be timing differences between the acquisition of newcapacity and the negotiation of applicable downstream sales agreements to match.Until new markets are developed, our Marketing segment sells greater portionsof its natural gas supply in less attractive short-term markets.

In the second quarter of 2005, our Marketing segmentincurred losses of $3.1 million compared with earning $0.7 million ofoperating income for the corresponding period in 2004. Included in operatingloss for the second quarter of 2005 are mark-to-market gains of approximately$3.9 million associated with derivative financial instruments that do notqualify for hedge accounting treatment under SFAS No. 133. These gains areoffset by losses of approximately $9.0 million resulting from thediscontinuance of hedge accounting for derivative financial instruments associatedwith forecasted transactions that we determined were not probable of occurring.In the second quarter of 2005, we revised our business strategy for the use ofderivative financial instruments associated with transportation of natural gasto afford us the ability to enter and exit markets in response to changingeconomic conditions. The flexibility provided by the revised strategy precludesus from continuing the use of hedge accounting with regard to thesetransactions. As a result of adopting this strategy, we determined that ourpreviously forecasted sales and purchases were not probable of occurringbecause of the likelihood the original transactions would be closed. We expecta majority of these net mark-to-market losses to be offset when the relatedphysical transactions are settled. Approximately $2.1 million of the netmark-to-market losses will not be recoverable and relate to hedges closed-outduring the second quarter. These amounts will be realized as reduced cash flowsover an approximate 18 month period. The Partnership will use its best effortsto mitigate or recover economic losses on this portion of the discontinuedderivative financial instruments (refer also to the discussion included belowunder Derivative Transactions, Note 4 of Item 1. Financial Statements,and Item 3. Quantitative and Qualitative Disclosures About Market Risk).

The Partnership usesderivative financial instruments to economically hedge potential commodityprice movements. Specifically, natural gas swaps and certain storage swaps arestrategies commonly used. Financial natural gas basis swap transactions areemployed to mitigate the risk on index pricing differentials between physicalnatural gas purchases and corresponding natural gas sales. When the natural gassales pricing index is different from the natural gas purchase pricing index,the Partnership is exposed to relative changes in those two index levels. Byentering into a basis swap between those two indices, the Partnership caneffectively lock in the margin on the combined natural gas purchase and thenatural gas sale, removing any market price risk on the physical transactions.In addition to natural gas basis swaps, the Partnership contracts for storageto assist balancing natural gas supply and end use market sales. In order tomitigate storage fees for the use of the storage capacity, the forward pricebetween the summer and winter (“spread”) is hedged by buying forward storageinjection swaps and selling storage withdrawal swaps. When these spread valuesincrease or decrease as a result of market price movements, the Partnershipearns additional profitability through the optimization of those hedges in boththe forward and daily markets. Although each of these hedge strategies aresound economic hedging techniques, these types of financial transactions do notqualify for hedge accounting under the SFAS No. 133 guidelines. As such,the non-qualified hedges are accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

***Six months ended June 30, 2005 compared with sixmonths ended June 30, 2004***

Our Marketing segmentincurred an operating loss of $1.7 million in the first half of 2005,compared with $2.9 million of operating income for the correspondingperiod in 2004. Included in the operating loss for the six months of 2005 aremark-to-market gains of approximately $5.3 million associated withderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133. These gains are offset by losses ofapproximately $9.0 million resulting from the discontinuance of hedge 

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accountingfor derivative financial instruments associated with forecasted transactionsthat we determined were not probable of occurring as discussed above in ourthree month analysis (refer also to the discussion included below underDerivative Transactions, Note 4 of Item 1. Financial Statements, andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

***Corporate***

Interest expense was $25.6million and $51.2 million for the three and six months ended June 30,2005, respectively, compared with $22.0 million and $43.6 million for thecorresponding periods in 2004. The increases are the result of higher debtbalances and higher weighted average interest rates of approximately 5.72% and5.86% during the three and six months ended June 30, 2005, compared withapproximately 5.39% and 5.24% during the same periods in 2004.

**LIQUIDITYAND CAPITAL RESOURCES**

We believe that our abilityto generate cash flow, in addition to our access to capital resources, issufficient to meet the demands of our current and future operating growth andinvestment needs. Our primary cash requirements consist of normal operatingexpenses, maintenance and expansion capital expenditures, debt servicepayments, distributions to partners and acquisitions of new assets orbusinesses. Short-term cash requirements, such as operating expenses,maintenance capital expenditures and quarterly distributions to partners, areexpected to be funded from our operating cash flows. We expect to fund long-termcash requirements for expansion projects and acquisitions from several sources,including cash flows from operating activities, borrowings under the commercialpaper program we established in April 2005 and our credit facilities, andthe issuance of additional equity and debt securities. Our ability to completefuture debt and equity offerings and the timing of any such offerings willdepend on various factors, including prevailing market conditions, interestrates, our financial condition and credit rating at the time.

In April 2005, weentered into the third amendment to the Amended and Restated Credit Agreementdated as of January 24, 2003 (the “Credit Facility”) to, among otherthings, extend the maturity of the Credit Facility for a period of five yearsto April 2010; increase the letter of credit sublimit from $100 millionto $175 million; and grant us the right to request, subject to approval by the Boardof Directors of Enbridge Management, L.L.C. (“Enbridge Management”), anincrease in commitments available under the Credit Facility up to an aggregateoutstanding principal amount of $1 billion.

Also in April 2005,we successfully entered the commercial paper market with the establishment ofour $600 million commercial paper program that is backstopped by our CreditFacility. We expect to reduce our short-term borrowing costs by accessing thecommercial paper market primarily to provide temporary financing for ouroperating activities, capital expenditures and acquisitions. We have repaid theentire amount previously outstanding under our Credit Facility from proceeds weobtained from issuing commercial paper under this program. Our Credit Facilityremains undrawn and available to backstop our commercial paper program. Underthe terms of our commercial paper program, we can issue commercial paper up tothe $600 million limit of our Credit Facility, reduced by the balance ofoutstanding Letters of Credit. At June 30, 2005, we had $390.0 million ofcommercial paper outstanding at a weighted average interest rate of 3.23% andoutstanding Letters of Credit totaling $121.2 million with availability underour commercial paper program of $88.8 million.

On February 11, 2005,we issued an additional 2,506,500 Class A common units at $49.875 perunit, which generated proceeds, net of offering expenses, of approximately$124.8 million. We used the proceeds from this offering to repayborrowings under our Credit Facility. Additionally, the General Partnercontributed $2.7 million to us to maintain its 2% general partner interestin the Partnership.

Working capital, definedas current assets less current liabilities, decreased by $1.2 million to $68.3 millionat June 30, 2005, compared with $69.5 million at December 31,2004. This decrease was 

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primarilyattributable to general timing differences in the collection on and payment ofour related party and current accounts.

At June 30, 2005,cash and cash equivalents totaled $82.4 million, compared with$78.3 million at December 31, 2004. Of the cash balance,$64.0 million ($0.925 per unit) is available for cash distributions to ourunitholders on August 12, 2005. Of this distribution, $53.3 millionwill be paid in cash, $10.5 million will be distributed in i-unitsto our i-unitholder and $0.2 million retained from our General Partner inrespect of this i-unit distribution.

***OperatingActivities***

Net cash provided byoperating activities for the six months ended June 30, 2005 was $123.7million, compared with $154.1 million for the same period in 2004. Thedecrease in 2005 was primarily due to general timing differences in thecollection on and payment of our related party and current accounts.

***InvestingActivities***

Net cash used in investingactivities during the six months ended June 30, 2005 was $357.6 million,compared with $199.7 million for the same period in 2004. The increase of$157.9 million was partially attributable to greater amounts we expendedfor the acquisition of the North Texas Gathering system and other natural gasgathering assets in 2005 than the amount we paid for the Mid-Continentand Palo Duro systems acquired in the first half of 2004. We acquired gatheringand processing assets in north Texas for approximately $164.6 million in January 2005and other natural gas gathering assets for approximately $21.3 million duringthe six months ended June 30, 2005. In addition to our acquisitions, wespent approximately $174.7 million in connection with our core maintenanceand system enhancement projects, representing an increase of$103.9 million over the $70.8 million we spent in the first half of2004, primarily due to the construction of our East Texas system expansion,which was completed in June 2005, and several smaller projects to expandour existing natural gas transmission and processing capacity as well as crudeoil storage facilities. Additional information regarding our capitalexpenditures is provided below.

***FinancingActivities***

Net cash provided byfinancing activities during the six months ended June 30, 2005 was$238.0 million, compared with $51.7 million for the correspondingperiod in 2004. The increase of $186.3 million in cash flow is primarilydue to the proceeds we received from the additional Class A common unitswe issued in February 2005 and net borrowings under our commercial paperprogram and Credit Facility, partially offset by an increase in distributionsto our partners. Distributions to our partners were higher in 2005 due to anincrease in the number of units outstanding, as well as a related increase inthe general partner incentive distributions resulting from the larger number ofunits outstanding.

**CAPITALEXPENDITURES**

We rely upon cash flowfrom our operating activities and access to the capital markets to provide thefunds necessary to execute our growth strategy and complete our projects. Oursuccess with generating and raising capital is a critical factor thatdetermines how much we actually spend. We believe our ability to generate orotherwise access the necessary capital resources is sufficient to meet thedemands of our current and future operating growth needs. Although we currentlyintend to make the forecasted expenditures discussed below, we may adjust thetiming and amounts of projected expenditures as necessary to adapt to changesin economic conditions.

We estimate our capital expenditures based on our longrange strategic operating and growth plans. These estimates may change due to factorsbeyond our ability to control including changes in supplier prices, resourceconstraints, or poor economic conditions. Additionally, estimates may change asa result of decisions made at a later date, which may include acquisitions,scope changes or operational considerations.

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Wecategorize capital expenditures as either core maintenance or systemenhancement expenditures. Core maintenance expenditures are those expendituresthat are necessary to maintain the service capability of our existing assetsand include the replacement of system components and equipment which are worn,obsolete or approaching the end of their useful lives. Enhancement expendituresimprove the service capability of our existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues and enable us to respond to governmental regulations and developingindustry standards. We made capital expenditures of approximately$174.7 million, including $13.3 million on core maintenanceactivities, during the six months ended June 30, 2005. For the full year2005, we anticipate capital expenditures to approximate $408 million, asillustrated in the following table below:
| ** **                   | ** ** | **(in millions)** | ** ** |
|------------------------------|------------|------------------------|------------|
| System enhancements          |       |                   | $          | 308 |   |   |
| Core maintenance  activities |       |                   | 43         |   |   |
| East Texas expansion         |       |                   | 57         |   |   |
|                         |       |                   | $408       |   |   |

 

As of June 30, 2005,we have contractual commitments totaling $19.2 million for materials andservices related to our organic growth projects. We expect to settle thesecommitments during the remainder of 2005 and 2006.

We anticipate funding ourcapital expenditures temporarily through our Credit Facility or our commercialpaper program, with permanent debt and equity funding being provided asappropriate. Core maintenance expenditures are expected to be funded byoperating cash flows.

We expect to incurcontinuing annual capital and operating expenditures for pipeline integritymeasures to both ensure regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are viewed to be consistent with industry trends.

**DERIVATIVE ACTIVITIES**

We use derivativefinancial instruments (i.e., futures, forwards, swaps, options and otherfinancial instruments with similar characteristics) to mitigate the volatilityof our cash flows and manage the purchase and sales prices of our commodities.Based on our risk management policies, all of our derivative financial instrumentsare employed in connection with an underlying asset, liability and/oranticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

Thefollowing table provides information about the timing and expected settlementamounts of our outstanding commodity derivative financial instruments at June 30,2005:
| ** **             | ** **   | **Notional**           | ** **   | **2005**     | ** **   | **2006**     | ** **   | **2007**     | ** **   | **2008**     | ** **   | **2009**     | ** **   | **2010**     | ** **   | **2011**     | ** **   | **2012**     | ** **   |
|------------------------|--------------|------------------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|
| ** **             | ** **   | **(in millions)** | ** **   |
| **Swaps**              | *** *** | *** ***           | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** |
| Natural gas(1)         |         | 580,791,099            |         | $            | (9.9         | )            | $            | (31.5        | )            | $            | (27.7        | )            | $            | (25.3        | )            | $            | (21.2        | )            | $            | (18.6 | ) | $ | (17.7 | ) | $ | (3.8 | ) |
| NGL(2)                 |         | 7,974,830              |         | (12.2        | )            | (10.2        | )            | (9.7         | )            | (3.4         | )            | —       |         | —       |         | —       |         | —       |         |
| Crude(2)               |         | 1,192,509              |         | (4.1         | )            | (6.2         | )            | (6.0         | )            | (3.9         | )            | (0.6         | )            | —       |         | —       |         | —       |         |
| **Options—calls** |         |                   |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 7,125,000              |         | (1.5         | )            | (3.5         | )            | (3.1         | )            | (2.7         | )            | (2.4         | )            | (2.1         | )            | (2.1         | )            | —       |         |
| **Options—puts**  |         |                   |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 7,585,000              |         | —       |         | —       |         | —       |         | —       |         | —       |         | —       |         | —       |         | —       |         |
| Totals                 |         |                   |         | $            | (27.7        | )            | $            | (51.4        | )            | $            | (46.5        | )            | $            | (35.3        | )            | $            | (24.2        | )            | $            | (20.7 | ) | $ | (19.8 | ) | $ | (3.8 | ) |

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(1)                 Notional amountsfor natural gas are recorded in millions of British thermal units (“MMBtu”).

(2)                 Notional amountsfor NGL and Crude are recorded in Barrels (“Bbl”).

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**OFF-BALANCE SHEET ARRANGEMENTS**

We do not have any off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

***Distribution Declaration***

On July 28, 2005, EnbridgeManagement’s Board of Directors declared a distribution payable on August 12,2005. The distribution will be paid to unitholders of record as of August 5,2005, of our available cash of $64.0 million at June 30, 2005, or$0.925 per common unit. Of this distribution, $53.3 million will bepaid in cash, $10.5 million will be distributed in i-units to our i-unitholderand $0.2 million will be retained from the General Partner in respect ofthis i-unit distribution.

**FUTURE PROSPECTS**

***Liquids***

Average daily crude oil deliveries on our Lakeheadsystem are expected to decrease by approximately 20,000 Bpd during 2005 toapproximately 1.38 million Bpd, from our previous forecast of 1.40 millionBpd. This also represents a year-over year decrease of approximately42,000 Bpd, from 2004 deliveries of 1.422 million Bpd. The decreaseis primarily attributable to the early January 2005 fire at the Suncor oilsands plant in Alberta, a major producer of crude oil in western Canada. Suncorexpects to return to full production capacity in September 2005 whichshould result in a substantial increase in western Canadian crude oil supplyand deliveries on our Lakehead system in the fourth quarter.

In June 2005, an Open Season was commenced by thePartnership and Enbridge Inc. (“Enbridge”) to confirm shipper support for theSouthern Access Mainline Expansion and Extension Program (“Southern AccessProgram”). The Mainline Expansion consists of up to three separate phases,which in aggregate is designed to provide an additional 400,000 Bpd of crudeoil capacity on the Enbridge/Lakehead mainline system from Hardisty, Alberta toChicago, Illinois. The U.S. portion of the Mainline Expansion program, from theinternational border to Chicago, will be undertaken on our Lakehead system at acost of approximately $760 million, taking into consideration the expectedsavings of proceeding with all three phases concurrently. The Southern AccessExtension will involve the construction of a new 30-inch diameter 300,000Bpd pipeline from a new interconnection with our Lakehead system, near Chicago,to hubs at Wood River and/or Patoka, Illinois, at a total cost of approximately$320 million. The Southern Access Extension will be undertaken by a U.S.subsidiary of Enbridge and integrated with our Lakehead system for rate-makingpurposes. The Mainline Expansion can be accomplished either as one project orin phases. The Open Season was successfully concluded in late July 2005with strong endorsement from shippers for Enbridge and the Partnership toproceed concurrently with all three phases of the Southern Access Program. As aresult, we and Enbridge will proceed with negotiation of final contract termswith individual shippers, or the Canadian Association of Petroleum Producers ontheir behalf, as well as obtaining Canadian and U.S. regulatory approvals.

Enbridge and the Partnership are seeking industryinput and support for the Southern Access Program through two parallel processes.First, with respect to the Mainline Expansion, we are seeking letters ofsupport from shippers which will provide input on the number of phases theydesire to trigger, as well as shipper support for the tolling methodologies forrecovery of costs. The second process relates specifically to the SouthernAccess Extension and involves an open season conducted in two stages. DuringStage I, prospective shippers are asked to submit non-binding expressions ofinterest, which will give an indication of the potential volumes of crude oilavailable for the Extension, as well as the preferred destination for the crude.If Enbridge decides to proceed to Stage II of the open season, prospectiveshippers will execute binding agreements providing volume commitments for theExtension. Assuming all 

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necessary approvals andother contingencies are satisfied, and the Southern Access Program proceeds asa single project, it is anticipated that all phases could be in-service by thefirst quarter of 2009.

In June 2005, Enbridge acquired the remaining 10%stake in the Spearhead Pipeline, giving it 100% ownership in the pipeline,which runs from Cushing, Oklahoma to Chicago. After a successful open season inthe fall of 2004, Enbridge is currently in the process of reversing the flow ofthe Spearhead Pipeline so that it will provide capacity to deliver125,000 Bpd into the major oil hub at Cushing by 2006. This line couldsubsequently be expanded to accommodate up to 160,000 Bpd. The FERCapproved the application for Spearhead transportation tariffs on March 3,2005. A portion of the Spearhead Pipeline’s revenue requirement will be rolledinto Enbridge’s Canadian mainline tariffs, which was approved in the secondquarter of 2005 by Canada’s National Energy Board (“NEB”). The NEB decision hasbeen appealed by one intervener based on jurisdictional grounds and Enbridge iswaiting for a response from Canada’s Federal Court of Appeal on whether theappeal will be heard. Enbridge expects that this appeal will not be successfuland therefore, is proceeding with the reversal project. We expect to benefitfollowing the reversal, as western Canadian crude oil will be carried on theLakehead system as far as Chicago, and then transferred to the SpearheadPipeline to continue to this new market.

During 2004, ExxonMobil Pipeline Company (“ExxonMobil”)approached the Canadian Association of Petroleum Producers and prospectiveshippers with a proposal to reverse the direction of flow on their Beaumont,Texas to Corsicana, Texas and their Corsicana, Texas to Patoka pipelines. Thecombined reversed pipeline will be linked to our Lakehead system at Chicago viathe Mustang Pipe Line Partners system to Patoka. Mustang Pipe Line Partnerssystem is 30% owned by an affiliate of Enbridge. ExxonMobil completed asuccessful open season with commitments of 50,000 Bpd, and have stated thatthey will proceed with the reversal, with plans to be in-service by the end of2005. The reversed pipeline is expected to transport 65,000 Bpd of westernCanadian heavy crude to the refinery market located in Beaumont on the U.S.Gulf Coast. The connection of the Lakehead system with this new market shouldalso support increased throughput on the Lakehead system; however, the reversedsystem will also be capable of transporting western Canadian crude moved viaother competing pipelines into Patoka.

Two proposals are currently being pursued to increasepipeline capacity for transportation of crude oil from the oil sands in Albertato the west coast of Canada, where it could be shipped by tanker to China,other Asia-Pacific markets and California.

The Gateway Pipeline is a new 30-inch crude oilpipeline with design capacity of 400,000 Bpd. In April 2005, a memorandumof understanding was entered into between Enbridge and PetroChina InternationalCompany Limited to cooperate on the development of the Gateway Pipeline inorder to supply approximately 200,000 Bpd of crude oil to China. A regulatoryapplication for the $2.5 billion (Canadian dollars), 720-mile pipelinewould have to be made in 2006 to achieve a late 2009-2010 in-servicedate, which is when Enbridge’s western Canada crude oil supply forecastindicates that oil sands production will have increased to the level thataccess to a major new market will be beneficial to producers. Enbridgeestimates that between 600,000 and 800,000 Bpd of incremental oil sandsproduction will be available by 2010.

Terasen Inc.’s TMX project, is a proposed capacityexpansion of their existing Trans Mountain Pipeline system, that runs fromAlberta to British Columbia, Canada and Washington state. In July 2005,Terasen Inc. filed an application with the NEB to increase the capacity oftheir Trans Mountain pipeline system from 225,000 Bpd to 260,000 Bpd., with aplanned in-service date of the first quarter of 2007.

These pipeline expansionsare in line with the Partnership’s expectations for increased access to new andexisting markets for western Canadian crude oil. The Partnership expects thegrowing supply of crude oil from the Alberta oil sands to exceed the pipelinecapacity to current and proposed markets which will require the development ofnew pipelines out of Western Canada.

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***Natural Gas***

We continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth. The market foracquiring energy transportation assets is active and competition amongprospective acquirers of assets has been significant. While we remain committedto making accretive acquisitions in or near areas where we already operate orhave a competitive advantage, we will continue to focus our efforts ondevelopment of our existing pipeline systems. Although our primary objective isto grow our natural gas business through acquisitions, we may also pursueopportunities to divest of any non-strategic natural gas assets as conditionswarrant.

We completed construction in June 2005 of our new500 MMcf/d East Texas Expansion Pipeline Project. This new pipelinerepresents a strategic link between producers both in the Barnett Shale area ofNorth Central Texas and the Bossier/Cotton Valley horizons in East Texas andnew markets accessible through the pipeline hub at Carthage, Texas. Carthageaccess is important to natural gas shippers because it offers a number ofpipeline connections which generally provide higher wellhead gas prices forproducers. The pipeline is operating within its originally projected capacitywith continued increases in utilization expected through the remainder of theyear resulting from negotiation of additional commercial arrangements, organicsupply growth, and other growth initiatives on our East Texas system.

In addition to the completion of the East TexasExpansion Pipeline Project, the Enbridge Management Board of Directorsapproved, and we initiated, a series of new projects to restart as well asconstruct certain treating and processing facilities on our East Texas system. Weexpect to complete these new projects in early 2006 at an estimated cost ofapproximately $75 million. Completion of these new projects will expand the serviceofferings we currently provide to our customers on the East Texas system.

Construction on our Anadarko system expansioncontinues. The first phase of the expansion added 100 MMcf/d of processingcapacity at a cost of $38 million and entered service in April 2005.We are now proceeding with increasing the scale of that processing plant to 160 MMcf/d.The cost of this second phase is approximately $14 million and we expectit to be complete by the end of the fourth quarter of 2005.

Our Bamagas system hasagreements to provide transportation of up to 276,000 MMBtu/d of natural gasfor a remaining period of 17 years to two utility plants that are indirectlyowned by Calpine Corporation (“Calpine”). The Bamagas system receives a fixeddemand charge of $0.07 per MMBtu of natural gas for 200,000 MMBtu/d, regardlessof whether the capacity is used. Calpine has recently experienced financialdifficulties that it is actively working to alleviate. Although we fully expectour customer to remain solvent and its plants to meet their obligations to usunder the terms of the transportation agreements, we are exposed to a potentialasset impairment of up to $50 million, representing the book value of thepipeline, should they be unable to fulfill their commitments. We are activelymonitoring Calpine’s financial condition and evaluating alternate uses for thesystem.

**REGULATORY MATTERS**

***FERCTransportation Tariffs-****Liquids*

Effective July 1, 2005, in compliance with theindexed rate ceilings allowed by the FERC, the Partnership increased its ratesfor transportation on the Lakehead, North Dakota and Ozark systems by anaverage of approximately 3.63%. For the Lakehead system, indexing only appliesto its base rates, not the surcharges for SEP II, Terrace and Facilities. ThePartnership anticipates that the increase in tariff rates will not have amaterial impact on the Partnership’s financial condition and results ofoperations. On the Lakehead system, the new rate for heavy crude movements fromthe International Border to Chicago is $0.89 per barrel, which reflects anapproximate 2.5 cents per barrel increase over rates filed effective April 1,2005.

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Effective April 1,2005, Enbridge Energy, Limited Partnership (“Lakehead Partnership”), asubsidiary of the Partnership, filed a new tariff with the FERC. This newtariff reflects the annual calculation of the SEP II and Facilitiessurcharges based on true-ups of prior year amounts and estimates for2005, and an adjustment for the Terrace surcharge as a result of lower thanexpected volumes moving on the Lakehead system. This filing increased thetariff for heavy crude oil movements from the Canadian border to Chicago,Illinois, by approximately $0.035 per barrel, to approximately $0.865 perbarrel.

***FERC Policy on Income Tax Allowances***

On May 4, 2005, the FERC adopted a policy topermit cost-of-service rates to reflect actual or potential incometax liability for all public utility assets, regardless of the form ofownership. The policy statement stems from an opinion issued by theU.S. Court of Appeals for the District of Columbia Circuit in *BP West Coast Products, LLC v. FERC* thatremanded the FERC’s decisions on tax allowance treatment in an oil pipelinerate proceeding involving SFPP, L.P., an unrelated pipeline company.

Under the policy, allentities or individuals owning public utility assets would be permitted anincome tax allowance on the income from those assets, provided that they havean actual or potential income tax liability on that public utility income. As aresult, a taxpaying corporation, partnership, limited liability corporation, orother pass-through entity would be permitted an income tax allowance onthe income imputed to the corporation, or to the partners or the members ofpass-through entities. Any pass-through entity seeking an incometax allowance in a specific rate proceeding will be required to establish thatits partners or members have an actual or potential income tax obligation onthe entity’s public utility income. Management is evaluating the new FERCpolicy. At this time we do not believe the adoption of this policy by the FERCwill have a material effect on our financial position, results of operations orcash flows.

***FERC Guidance on Accounting for Integrity ManagementCosts***

In June 2005, theFERC issued guidance describing how FERC-regulated companies should account forcosts associated with implementing the pipeline integrity managementrequirements of the U.S. Department of Transportation’s Office of PipelineSafety. Under the guidance, costs to 1) prepare a plan to implement theprogram, 2) identify high consequence areas, 3) develop and maintain a recordkeeping system and 4) inspect, test and report on the condition of affectedpipeline segments to determine the need for repairs or replacements, arerequired to be expensed. Costs of modifying pipelines to permit in-lineinspections, certain costs associated with developing or enhancing computersoftware and costs associated with remedial and mitigation actions to correctan identified condition can be capitalized. The guidance is effective January 1,2006, to be applied prospectively. We are currently evaluating the effect thatapplication of this order will have on our financial statements.

**Item 3.**                        Quantitativeand Qualitative Disclosures About Market Risk

This information updates, and you should read it inconjunction with, our quantitative and qualitative disclosures about marketrisks reported in our Annual Report on Form 10-K, as amended, forthe year ended December 31, 2004, in addition to information presented inItems 1 and 2 of this Quarterly Report on Form 10-Q.

Our net income and cash flows are subject tovolatility stemming from changes in commodity prices of natural gas, NGLs,condensate and fractionation margins (the relative price differential betweenNGL sales and offsetting natural gas purchases). This market price exposureexists within our Natural Gas and Marketing segments. To mitigate thevolatility of our cash flows, we use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to manage the purchase and sales prices of the commodities.Based on our risk management policies, all of our derivative financialinstruments are employed in connection with an underlying asset, liabilityand/or anticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

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Thefollowing tables provide information about our derivative financial instrumentsat June 30, 2005 and December 31, 2004, with respect to our commodityprice risk management activities for natural gas and NGLs, including crude:
|                                  | ** ** | **At June 30, 2005** | ** ** | **At December 31,   2004** | ** ** |
|----------------------------------|------------|-------------------------------------|------------|--------------------------------------|------------|
| ** **                       | ** ** | ** **                          | ** ** | ** **                           | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                       | ** ** | **Commodity**                       | ** ** | **Notional**(1)                      | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | ** Liability ** | ** ** |
| ***Contracts maturing in 2005*** |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                  |       | Natural  Gas                        |       | 91,953,108                           |       | $ | 7.11 |   | $ | 6.51 |   | $ | 57.2 |   | $ | (2.7 | ) | $ | 8.1 |   |   | $ | (54.5 | ) |   |
| Receive fixed                    |       | Natural Gas                         |       | 90,713,493                           |       | 6.51 |   | 7.23 |   | 3.3 |   | (67.5 | ) | 48.3 |   |   | (25.9 | ) |   |
| /pay variable                    |       | NGL                                 |       | 2,043,412                            |       | 27.26 |   | 33.28 |   | — |   | (12.2 | ) | 1.0 |   |   | (8.0 | ) |   |
|                             |       | Crude                               |       | 173,880                              |       | 34.41 |   | 58.44 |   | — |   | (4.1 | ) | — |   |   | (3.2 | ) |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                    |       | Natural  Gas                        |       | 16,962,369                           |       | 6.90 |   | 6.92 |   | 0.2 |   | (0.4 | ) | 0.7 |   |   | (2.4 | ) |   |
| *Options*                        |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                         |       | 552,000                              |       | 7.38 |   | 4.74 |   | — |   | (1.5 | ) | — |   |   | (1.7 | ) |   |
| Puts                             |       | Natural  Gas                        |       | 1,012,000                            |       | 7.37 |   | 4.13 |   | — |   | — |   | 0.1 |   |   | — |   |   |
| ***Contracts maturing in 2006*** |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                  |       | Natural  Gas                        |       | 124,253,066                          |       | 7.72 |   | 6.83 |   | 108.0 |   | (0.2 | ) | 4.2 |   |   | (7.8 | ) |   |
| Receive fixed                    |       | Natural Gas                         |       | 127,700,926                          |       | 6.72 |   | 7.85 |   | 0.2 |   | (139.1 | ) | 7.8 |   |   | (23.3 | ) |   |
| /pay variable                    |       | NGL                                 |       | 2,602,815                            |       | 28.59 |   | 32.69 |   | 0.5 |   | (10.7 | ) | 0.5 |   |   | (4.1 | ) |   |
|                             |       | Crude                               |       | 342,900                              |       | 39.87 |   | 58.86 |   | — |   | (6.2 | ) | 0.4 |   |   | (1.4 | ) |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable               |       | Natural  Gas                        |       | 1,887,781                            |       | 7.80 |   | 8.00 |   | — |   | (0.4 | ) | — |   |   | (0.2 | ) |   |
| *Options*                        |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                         |       | 1,095,000                            |       | 7.99 |   | 4.74 |   | — |   | (3.5 | ) | — |   |   | (1.8 | ) |   |
| Puts                             |       | Natural  Gas                        |       | 1,095,000                            |       | 7.99 |   | 3.40 |   | — |   | — |   | — |   |   | — |   |   |
| ***Contracts maturing in 2007*** |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                  |       | Natural  Gas                        |       | 37,782,671                           |       | 7.50 |   | 6.87 |   | 22.3 |   | (0.3 | ) | 0.6 |   |   | (8.2 | ) |   |
| Receive fixed                    |       | Natural Gas                         |       | 41,914,481                           |       | 6.44 |   | 7.72 |   | 0.9 |   | (50.6 | ) | 8.5 |   |   | (15.8 | ) |   |
| /pay variable                    |       | NGL                                 |       | 2,599,165                            |       | 27.62 |   | 31.66 |   | 0.9 |   | (10.6 | ) | 0.4 |   |   | (4.0 | ) |   |
|                             |       | Crude                               |       | 306,555                              |       | 36.41 |   | 57.82 |   | — |   | (6.0 | ) | 0.2 |   |   | (1.3 | ) |   |
| Receive variable                 |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable               |       | Natural  Gas                        |       | 214,000                              |       | 7.15 |   | 7.27 |   | — |   | — |   | — |   |   | — |   |   |
| *Options*                        |       |                                |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                         |       | 1,095,000                            |       | 7.75 |   | 4.74 |   | — |   | (3.1 | ) | — |   |   | (1.5 | ) |   |
| Puts                             |       | Natural  Gas                        |       | 1,095,000                            |       | 7.75 |   | 3.40 |   | — |   | — |   | — |   |   | — |   |   |
|                                  |            |                                     |            |                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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| ***Contracts maturing in 2008***     |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|--------------------------------------|--------|--------------|--------|------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|
| *Swaps*                              |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                     |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                      |   | Natural  Gas |   | 8,047,000  |   | 7.47   |   | 7.00   |   | 3.4    |   | — |   | — |   |   | (1.9   | )      |   |
| Receive fixed                        |   | Natural Gas  |   | 16,262,000 |   | 5.50   |   | 7.48   |   | 0.6    |   | (29.3  | )      | 2.3    |   |   | (12.2  | )      |   |
| /pay variable                        |   | NGL          |   | 729,438    |   | 25.59  |   | 30.93  |   | — |   | (3.4   | )      | 0.7    |   |   | (0.2   | )      |   |
|                                 |   | Crude        |   | 268,799    |   | 40.72  |   | 57.01  |   | — |   | (3.9   | )      | 0.5    |   |   | — |   |   |
| *Options*                            |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas  |   | 1,098,000  |   | 7.37   |   | 4.74   |   | — |   | (2.7   | )      | — |   |   | (1.2   | )      |   |
| Puts                                 |   | Natural  Gas |   | 1,098,000  |   | 7.37   |   | 3.40   |   | — |   | — |   | 0.1    |   |   | — |   |   |
| ***Contracts  maturing in 2009***    |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed                        |   | Natural Gas  |   | 7,300,000  |   | 3.63   |   | 7.05   |   | — |   | (21.2  | )      | — |   |   | (9.8   | )      |   |
| /pay variable                        |   | Crude        |   | 100,375    |   | 49.43  |   | 56.45  |   | — |   | (0.6   | )      | — |   |   | — |   |   |
| *Options*                            |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas  |   | 1,095,000  |   | 7.05   |   | 4.74   |   | — |   | (2.4   | )      | — |   |   | (1.1   | )      |   |
| Puts                                 |   | Natural  Gas |   | 1,095,000  |   | 7.05   |   | 3.40   |   | — |   | — |   | 0.2    |   |   | — |   |   |
| ***Contracts  maturing after 2009*** |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  fixed                       |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                        |   | Natural  Gas |   | 15,796,500 |   | 3.63   |   | 6.85   |   | — |   | (40.0  | )      | — |   |   | (18.3  | )      |   |
| *Options*                            |   |         |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas  |   | 2,190,000  |   | 6.79   |   | 4.74   |   | — |   | (4.0   | )      | — |   |   | (2.0   | )      |   |
| Puts                                 |   | Natural Gas  |   | 2,190,000  |   | 6.79   |   | 3.40   |   | $      | 0.1    |   | — |   | 0.5    |   |   | — |   |   |
|                                      |        |              |        |            |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |  |

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(1)                 Volumes of Natural gas are measured inMMBtu, whereas NGL and Crude are measured in Bbl.

(2)                 Weighted average prices received andpaid for Natural gas are in $/MMBtu and in $/Bbl for NGL and Crude.

(3)                 The fair value isdetermined based on quoted market prices at June 30, 2005 and December 31,2004, respectively, discounted using the swap rate for the respective periodsto consider the time value of money. Fair values are presented in millions ofdollars.

***Accounting Treatment***

All derivative financialinstruments are recorded in the consolidated financial statements at fairmarket value and are adjusted each period for changes in the fair market value(“mark-to-market”). Under the guidance of SFAS No. 133,changes in the fair market value of derivatives that qualify as highlyeffective cash flow hedges are recorded as components of Accumulated othercomprehensive loss until the hedged transactions occur (“hedge accounting”).Hedge accounting can apply to either a hedge of future cash flows or the fairvalue of an asset or liability. Any ineffective portion of a cash flow hedge’schange in fair value is recognized each period in earnings. When the hedgedtransaction occurs, the fair value of the 

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derivativeis recognized in earnings, along with the offsetting fair value of the physicaltransaction. For those derivative financial instruments that do not qualify forcash flow hedge accounting, the total change in fair value is recorded directlyin earnings each period. Our preference, whenever possible, is for ourderivative financial instruments to receive hedge accounting treatment in orderto mitigate the noncash earnings volatility that arises under mark-to-marketaccounting treatment. However, to qualify for cash flow hedge accounting, veryspecific requirements must be met in terms of hedge structure, hedge objectiveand hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have three primary instances where the hedge structure does notmeet the requirements to apply hedge accounting and therefore, these financialinstruments are considered ‘non-qualified’ under SFAS No. 133. In theseinstances, the impacts of mark-to-market accounting for our non-qualifiedhedges are recorded in our Consolidated Statements of Income. Thesenon-qualified derivative financial instruments must be adjusted to their fairmarket value, or marked-to-market, each period, with the increasesand decreases in fair value recorded as increases and decreases in Cost ofnatural gas on our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often besignificant from period to period, but have no cash flow impact relative tochanges in market prices. The cash flow impact occurs when the underlyingphysical transaction takes place in the future and an associated financialinstrument contract settlement is made.

The three instancesof non-qualified hedges are as follows:

1.     In ourMarketing segment, when the pricing index used for gas sales is different fromthe pricing index used for gas purchases, we are exposed to relative changes inthose two indices. By entering into a basis swap between those two indices, wecan effectively lock in the margin on the combined gas purchase and gas sale,removing any market price risk on the physical transactions. Although thisrepresents a sound economic hedging strategy, these types of derivativetransactions do not qualify for hedge accounting under SFAS No. 133, asthe ultimate cash flow has not been fixed, only the margin.

2.     In ourMarketing segment, when we use derivative financial instruments to hedge marketspreads around our owned or contracted assets, such as our gas storageportfolio, the underlying forecasted transaction may or may not occur in thesame period as originally forecast. This can occur as we have the flexibilityto make these changes in the underlying injection or withdrawal schedule, givenchanges in market conditions. Therefore, these transactions do not qualify forhedge accounting treatment under SFAS No. 133, as the forecastedtransaction is no longer probable of occurring as originally set forth in thehedge documentation.

3.     In our Natural Gas segment, we had previously entered intonatural gas collars in order to hedge the sales price of natural gas. Thenatural gas collars were based on a NYMEX price while the physical gas saleswere based on a different index. To better align the index of the natural gascollars with the index of the underlying sales, we de-designated theoriginal hedging relationship and contemporaneously re-designated thenatural gas collars as hedges of physical natural gas sales with a NYMEXpricing index to better match the indices. This is a sound economic hedgingstrategy, however, since these instruments were out of the money at re-designation,they are considered net written options under SFAS No. 133. Therefore,these instruments do not qualify for hedge accounting upon re-designationand are now accounted for in the Consolidated Statements of Income through mark-to-marketaccounting, with their changes in fair value from the date of de-designationrecorded to earnings each period. As a result, our operating income 

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will be subject togreater volatility due to movements in the prices of natural gas until theseunderlying long-term transactions are settled.

***Discontinuance of Hedge Accounting***

During the second quarter of 2005, we discontinuedapplication of hedge accounting in connection with some of our derivativefinancial instruments designated as hedges of forecasted sales and purchases ofnatural gas. We discontinued application of hedge accounting when we determinedit was no longer probable that the originally forecasted purchases and sales ofnatural gas would occur by the end of the originally specified time period, orwithin an additional two-month period of time thereafter. One of the keycriteria to achieve hedge accounting under SFAS No. 133, is that theforecasted transaction is probable of occurring as originally documented in thehedge documentation. As a result, we recognized previously deferred unrealizedlosses in our Marketing segment of approximately $9.0 million from thediscontinuance of hedge accounting. In doing so, we reclassified the $9.0million to Cost of natural gas on our Consolidated Statements of income fromAccumulated other comprehensive income. Going forward, the discontinuedderivative financial instruments are considered to be non-qualified under SFAS No. 133,and must now be marked-to-market each period, with the increasesand decreases in fair value recorded as increases and decreases in earnings. Includedin the loss from discontinuance are approximately $2.1 million of netmark-to-market losses that relate to hedge positions that were closed-outduring the second quarter.

Thefollowing table presents the gains and losses associated with changes in thefair value of our derivatives which are recorded as an element of Cost ofnatural gas in our Consolidated Statements of Income and disclosed as areconciling item on our Statements of Cash Flows:
| ** **                                                   | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,**            | ** ** |
|--------------------------------------------------------------|------------|-------------------------------------------------|------------|----------------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                      | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                          | ** ** |
| Natural Gas  segment                                         |       |                                            |       |                                                     |       |   |   |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                            | $          | (1.8                                                     | )          |   |   | $ | — |   |   | $ | (2.0 | ) | $ | — |   |
| Non-qualified hedges                                         |       |                                            | (2.9       | )                                                        |       |   | — |   |   | (11.1 | ) | — |   |
| Marketing                                                    |       |                                            |       |                                                     |       |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                            | 3.9        |                                                     |       |   | (1.9 | ) |   | 5.3 |   | (1.7 | ) |
| Discontinuance                                               |       |                                            | (9.0       | )                                                        |       |   | — |   |   | (9.0 | ) | — |   |
| Derivative fair value  loss                                  |       |                                            | $          | (9.8                                                     | )          |   |   | $ | (1.9 | ) |   | $ | (16.8 | ) | $ | (1.7 | ) |
|                                                              |            |                                                 |            |                                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our highlyeffective cash flow hedges in our Consolidated Statements of ComprehensiveIncome until the derivative financial instruments are settled, at which timethey are reclassified to earnings. For the three and six months ended June 30,2005, we reclassified unrealized losses of $9.4 million and $25.2 million, from Accumulated other comprehensive lossto Cost of natural gas on our Consolidated Statements of Income for the fairvalue of derivative financial instruments that were settled.

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Our derivativefinancial instruments are included at their fair values in the ConsolidatedStatements of Financial Position as follows:
| ** **                   | ** ** | **June 30,  2005** | ** ** | **December 31,  2004** | ** ** |
|------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**  | ** ** |
| Receivables, trade and other |       | $                       | 5.3        |                        |       | $ | 8.2 |   |   |
| Other assets, net            |       | 9.4                     |       |                        | 10.1       |   |   |
| Accounts payable  and other  |       | (60.8                   | )          |                        | (45.9      | ) |   |
| Deferred credits             |       | (182.5                  | )          |                        | (99.6      | ) |   |
|                         |       | $                       | (228.6     | )                           |       | $ | (127.2 | ) |   |

 

The increase in our obligation associated with ourderivative activities from December 31, 2004 to June 30, 2005 is primarilydue to the significant increases in forward natural gas and NGL prices. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales agreements.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments. All of our counterparties were rated “A” or better byall major credit rating agencies.

**Item 4.**                        Controlsand Procedures

The Partnership andEnbridge  maintain systems of disclosure controls and procedures designedto provide reasonable assurance that we are able to record, process, summarizeand report the information required in our annual and quarterly reports underthe Securities Exchange Act of 1934. Our management has evaluated theeffectiveness of our disclosure controls and procedures as of June 30,2005. Based upon that evaluation, our principal executive officer and principalfinancial officer concluded that our disclosure controls and procedures areeffective to accomplish their purpose. In conducting this assessment, ourmanagement relied on similar evaluations conducted by employees of Enbridgeaffiliates who provide certain treasury, accounting and other services on ourbehalf. No changes in our internal control over financial reporting were madeduring the three months ended June 30, 2005, that would materially affectour internal control over financial reporting, nor were any corrective actionswith respect to significant deficiencies or material weaknesses necessarysubsequent to that date.

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**PART II—OTHER INFORMATION**

**Item 1.**                        LegalProceedings

Refer to Part I,Item 1. Financial statements, Note 7, which is incorporated herein byreference.

**Item 6.**                        Exhibits

Eachexhibit identified below is filed as part of this document. Exhibits notincorporated by reference to a prior filing are designated by an “*”; allexhibits not so designated are incorporated herein by reference to a previousfiling as indicated.
| 3.1   |   | Certificate of Limited Partnership of the  Partnership (incorporated by reference to Exhibit 3.1 to the  Partnership’s Registration Statement No. 33-43425).                                                                                                                                                                                                                                                                                                                                      |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of Amendment  to Certificate of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.2 to the Partnership’s 2000 Form 10-K/A  dated October 9, 2001).                                                                                                                                                                                                                                                                                                 |
| 3.3   |   | Third Amended and  Restated Agreement of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.1 to the Partnership’s Quarterly Report on  Form 10-Q filed November 14, 2002).                                                                                                                                                                                                                                                                                     |
| 4.1   |   | Form of Certificate  representing Class A Common Units (incorporated by reference to Exhibit 4.1  to the Partnership’s 2000 Form 10-K/A dated October 9, 2001).                                                                                                                                                                                                                                                                                                                    |
| 10.1  |   | Third Amendment to the  Amended and Restated Credit Agreement, dated as of January 24, 2003 (as  amended by the First Amendment, dated January 12, 2004 and the Second  Amendment, dated as of April 26, 2004), by and among the Partnership,  the lenders from time to time parties thereto, and Bank of  America, N.A., as administrative agent (incorporated by reference to  Exhibit 10.1 to the Partnership’s Current Report on Form 8-K  filed on April 19, 2005). |
| 10.2  |   | Commercial Paper Dealer  Agreement between the Company, as Issuer, and Banc of America  Securities LLC, as Dealer, dated as of April 21, 2005 (incorporated  by reference to exhibit 10.1 to the Partnership’s Current Report on  Form 8-K filed May 3, 2005).                                                                                                                                                                                                                     |
| 10.3  |   | Commercial Paper Dealer  Agreement between the Company, as Issuer, and Deutsche Bank  Securities Inc., as Dealer, dated as of April 21, 2005  (incorporated by reference to exhibit 10.2 to the Partnership’s Current  Report on Form 8-K filed May 3, 2005).                                                                                                                                                                                                                      |
| 10.4  |   | Commercial Paper Dealer  Agreement between the Company, as Issuer, and Goldman, Sachs & Co.,  as Dealer, dated as of April 21, 2005 (incorporated by reference to  exhibit 10.3 to the Partnership’s Current Report on Form 8-K  filed May 3, 2005).                                                                                                                                                                                                                      |
| 10.5  |   | Commercial Paper Dealer  Agreement between the Company, as Issuer, and Merrill Lynch Money  Markets Inc., as Dealer, dated as of April 21, 2005 (incorporated  by reference to exhibit 10.4 to the Partnership’s Current Report on  Form 8-K filed May 3, 2005).                                                                                                                                                                                                                   |
| 10.6  |   | Issuing and Paying  Agency Agreement between the Company and Deutsche Bank Trust Company  Americas, dated as of April 21, 2005 (incorporated by reference to  exhibit 10.5 to the Partnership’s Current Report on Form 8-K  filed May 3, 2005).                                                                                                                                                                                                                                         |
| 31.1* |   | Certification of Chief  Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                  |
| 31.2* |   | Certification of Chief  Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                       |
| 32.1* |   | Certification of Chief  Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                  |
| 32.2* |   | Certification of Chief  Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                       |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.
| ** **                 |   | **ENBRIDGE ENERGY PARTNERS,  L.P.**                                                                         |
|----------------------------|--------|-------------------------------------------------------------------------------------------------------------|
| ** **                 |   | (Registrant)                                                                                                |
|                       | By:    | Enbridge Energy  Management, L.L.C.  as delegate of  Enbridge Energy Company, Inc.  as General Partner |
| Date: August 5,  2005 | By:    | /s/ DAN C. TUTCHER                                                                                          |
|                       |   | Dan C. Tutcher                                                                                              |
| * *                   |   | *President and Director*                                                                                    |
| * *                   |   | *(Principal Executive Officer)*                                                                             |
| Date August 5, 2005   | By:    | /s/ MARK A. MAKI                                                                                            |
| * *                   |   | Mark A. Maki                                                                                                |
| * *                   |   | *Vice President, Finance*                                                                                   |
| * *                   |   | *(Principal Financial Officer)*                                                                             |

 

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